1

DRILLING PROGRAMME

Capella L17H

October 21th, 2011

Version 2.0

COPY No. 1

(See copy distribution list)

2

Omb Block

AUTHORIZATION AND APPROVAL

Prepared by:

_______________________________

Oscar Alfonso Diaz Osorio.

Dril ling Director

Date: Oct - 2011

_______________________________

David Ricardo Pedreros

Exploration Geologist

Date: Oct - 2011

Reviewed by:

_______________________________

Zheng Zhenguo

Drilling Deputy Manager

Date: Oct - 2011

Approved by:

_______________________________

Juan Carlos Ramn

Exploration and Business Vice President

Date: Oct - 2011

_________________________________

Yu Dunyuan

Drilling Vice President

3

WELL PROGRAMME DISTRIBUTION LIST

Copies of this document sent to:

a) Operations central files (original

sign-off copy)*

EEC Bogot file

b) Drilling Vice President & Manager Yu Dunyuan

c) Drilling Deputy Manager Zheng Zhenguo

d) Exploration and Business Vice President Juan Carlos Ramn

e) Drilling Director Oscar A. Diaz O.

f) Kerui 7502 Drilling Crew Luis Alfonso Ramirez

4

Contents

Contents .............................................................................................................. 4

1 G&G Summary .......................................................................................... 7

1.1 Well proposal ................................................................................................................ 7 1.2 General information ...................................................................................................... 8 1.3 G&G well objectives .................................................................................................... 9

1.4 G&G target/objective description, coordinates and shape ......................................... 10 1.6 Formation Tops / Dip / Dip azimuth / lithological description ................................ 13 1.7 G&G TD Criteria ..................................................................................................... 14 1.8 TD contingencies ..................................................................................................... 17

1.9 G&G Critical Issues related to Objectives and target/reservoir contingency requirements ........................................................................................................................... 17

G&G Target and objectives critical issues ........................................................................ 17 1.10 G&G Well Evaluation Requirements (logging/coring/sampling) ........................... 18

Open Hole LWD ............................................................................................................... 18 Anticipated testing requirements ...................................................................................... 18 1.11 Offset well information ........................................................................................... 19

1.12 Pore Pressure Prognosis .......................................................................................... 20 1.13 Offset Wells Fluid Contacts ..................................................................................... 20

1.14 Well testing Requirements ....................................................................................... 20

2. Drilling Equipment ..................................................................................... 17

2.1 Requirements for equipment selection ....................................................................... 17 2.2 The Drilling rig and key equipment configuration ..................................................... 17

3 Casing Program ......................................................................................... 18

3.1 Casing program design ............................................................................................... 18

4 Well Path Planning .................................................................................... 20

5 Requirements for Wellbore Quality ........................................................ 22

5.1 Hole quality standards in horizontal development well ............................................. 22

5.2 Cementing quality standards ...................................................................................... 23

6 BHA Program ............................................................................................ 24

7 Drill Bit Program recommendation ........................................................ 24

7.1 Bit type selection recommended................................................................................. 25 7.2 Drilling parameter recommended ............................................................................... 25

5

8 Drilling Fluid Program ............................................................................. 25

8.1 Guidelines for drilling fluid application ..................................................................... 25 8.2 Drilling Fluid Design Principle .................................................................................. 26

8.3 Drilling fluid systems and basic formulations ............................................................ 26 8.5 Drilling fluid volumes and reserve of drilling fluid materials .................................... 27 8.5.1 Expected drilling fluid volumes .............................................................................. 27 8.6 Solids control equipment and application requirements............................................. 27 8.7 Requirements for Drilling Fluid Test Instruments ...................................................... 28

8.8 Requirements for Drilling Fluid Management on the Surface ................................... 28

9 Cementing Program .................................................................................. 29

9.1 Guidelines for ensuring cementing quality and oil well life ...................................... 29

9.2 Selection of Cementing and Completion Technologies.............................................. 29 9.3 Casing String Design .................................................................................................. 30 9.4 Cementing pipe string design ..................................................................................... 31

9.5 Selection and placement of centralizers ..................................................................... 32 9.6 Cement Slurry Design ................................................................................................ 32

10 Reservoir Protection Program ............................................................... 34

11 Well Control Program ............................................................................. 35

11.1 Selection of well control equipment ......................................................................... 35

11.2 Requirements for BOP System Inspection and Testing ............................................ 37

11.3 Installation of the BOP System ................................................................................. 38

12 Operation Guidelines for Each Hole Section ........................................ 39

12.1 Pre-spud preparation and site construction ............................................................... 39

.......................................................................................................... 40 12.3 12 1/4 hole section ................................................................................................... 41 12.4 8 1/2" hole drilling .................................................................................................... 43

12.5 Precautions for drilling hazards ................................................................................ 43

13 Wellhead equipment for completion ..................................................... 47

13.1 Casing head specification ......................................................................................... 47

13.2 Wellhead protection .................................................................................................. 47 13.3 Completion requirements ......................................................................................... 47

14 HSE requirements ................................................................................... 49

14.1 Basic requirements ................................................................................................... 49 14.2 Liquid and solids waste managment program .......................................................... 50 14.3 Waste management objects (HSE) ............................................................................ 50

6

15. Logistic issues ............................................................................................. 51

16 Requirements for drilling information report ...................................... 51

17 Drilling cycle forecast .............................................................................. 52

7

1 G&G Summary

1.1 Well proposal

Energy PLC Suc. Colombia is proposing to drill Capella-L17H Horizontal Development Well from the

Capella-L location, under Omb E&P Contract in Capella Field as a horizontal well towards the mid

area of Capella field. Capella-L17H will be drilled as horizontal well and is located in Los Pozos

Village (Colombia) (Figures 1 to 3). Capella Structure is a faulted anticline NE oriented about 28 Km

NE-SW by 4.5 Km NW-SE (Figure 4 to 7).

Capella-L17H will be conducted as a Horizontal well to reach and navigate through the Mirador Sand

reservoir (producing in Capella Wells), in a central position in the Capella structure (Figure 4 to 7).

Capella-L17H would TD about 5190, 20ft MD, therefore it is not expected to reach Mirador OWC

(-2159ft TVDss), based on the same contour interval that was encountered by the Capella-L11 Well,

(Figure 8).

Capella-L17H is designed to produce from Mirador Upper Sand. This well will be conducted in

horizontal profile to navigate about 274, 4 meters up dip in SE direction through Mirador Sand Horizon

2 to confirm the oil production increasing shown in horizontal wells from location F.

Figure 1. Capella-L17H location trajectory from Capella-L toward Capella-F location

8

The principal risks associated with the well are:

Minor changes of the Mirador Sandstones.

Navigate the most along Mirador Sand # 2.

Sidetrack if real trajectory is too different from plan.

Prognosis top depth from seismic information could change after drilling depth real section.

Water coning as we found the OWC in Capella L11.

Figure 2. TVDss Map Top Mirador with Capella-L17H trajectory with SE direction that will navigate up dip in

the western flank of anticline

1.2 General information

Table 1-1 Well general identification

Description Data Comments

Required well operations Purpose/Target: Horizontal Well

Proposed Well Name: Capella-L17H

Target Horizons: Mirador Sand Horizon 2

Lahee Well Classification: Development

Well Type: Development

Drilling Classification:

Completion Size:

Well Location: County La Macarena (Meta)

9

Well Surface Coordinates GAUSS (Bogot

Origin):

N = 724.792,72 m

E = 943.584,93 m

Target Coordinates:

N = 724.432,31 m

E = 943.929,19 m

Well Bottom Coordinates GAUSS (Bogot

Origin):

N = 724.233,93 m

E = 944.118,68 m

Primary Target: Mirador Sand Horizon 2

Objective Depth: -2105 ft (Subsea TVDss)

4290,1 ft MD 3338,0 ft TVD

Navigation Distance 274,35 m, 900ft

Ground level elevation: Location GLE 1212.92 ft

Rotary Table Elevation: 1232,92 ft amsl (Aprox. 20 above

GL)

Expected well total depth: 5190,2 ft MD 3338,0ft TVD ( -2105

ft TVss)

Proposed Spud Date: November 4th, 2011

1.3 G&G well objectives

Increase production rates through increasing drainage length of Mirador Sand A, by drilling

274m (900ft) up dip in Mirador Sand Horizon 2 from Capella-L location (Figure 5, 8 and 9).

Drill Capella-L17H Horizontal well in Southeast direction with 136 average Azimuth (Figure 3).

Drill Capella-L17H horizontal well parallel to Capella-F10H, Capella-12H ST and Capella-F13H

(Figure 4).

Navigate the most within horizon 2 of Mirador Sand A, while drilling horizontal well (Figure 8).

Stay higher than OWC @ -2159ft TVDss, found in Capella-L11 that reached only Horizon 1 with

oil (Figure 8 and 9).

Test the oil production capability of the Mirador sandstones and verify the continuity of producer

sands and petrophysical properties.

Control Mirador Sand Horizon position by acquiring Resistivity and GR logs with LWD tool.

Control the lower part of Arrayan that creates wash-outs. Take into account lessons learn in

Capella F7, Capella-F10H, Capella-F12H ST and Capella-F13H.

Deliver well in full compliance with the well Integrity requirements.

10

1.4 G&G target/objective description, coordinates and shape

Capella-L17H will be drilled from the following cellar center coordinates in Capella L location:

Center cellar Coordinates GAUSS (Bogot

Origin)

N = 724.792,72 m

E = 943.584,93 m

Capella-L17 Horizontal

Capella-L17 Horizontal will be drilled to reach the next target coordinates until the bottom as follows

(Figure 3 and 4):

Capella-L17 Horizontal Entry Point -Target Coordinates GAUSS (Bogot Origin):

N = 724.432,31 m

E = 943.929,19 m

Capella-L17 Horizontal Well Bottom Coordinates GAUSS (Bogot Origin):

N = 724.233,93 m

E = 944.118,68 m

11

Figure 3 Vertical Profile and Plane View of Capella-L17H Plan

12

Figure 4 Plane View of Capella-F10H, Capella-F13H, Capella-F12HST, Capella-F16H drilled and Proposed Capella-L17H

Plan over TVDss Mirador Structural Map.

1.5 Reservoir description

Mirador reservoir data

Gross Thickness 45 feet TVD (Mirador Horizon 2)

Mirador Sand Oil Water Contact -2159 feet TVDSs

Target Coordinates at top of

reservoir GAUSS (Bogot Origin) N =724.432,31 m

E =943.929,19 m

Target shape and area Faulted anticline (22,000 acres)

Last reservoir pressure 1312.69 psi at 3362 feet (TVD)

13

1.6 Formation Tops / Dip / Dip azimuth / lithological description

Prognosis Horizontal Hole

FORMATION TVD

(feet) Top TVDss

(feet) MD

(feet)

Quaternary 0 1212,93 0

Fm. Arrayn 155,00 1077,93 155,00

Fm. Mirador 3298,00 -2065,10 3888,90

Fm. Mirador Horizon 2 3338,00 -2105,10 4290,10

Max TD 3333,00 -2100,10 5190,20

* TVD BRT = TVDSS + GLE + RTE (Assume RTE = 20 ft)

Note: The drilling program indicates the Capella-L17H well TD depth @ +/- 5190 ft MD. However

in case of Sand A thickness variation, the plan is to resume drilling up to EEC central offices geologist

indications.

Arrayn Formation

This formation was made up primarily of multicolor soft claystones and siltstones with minor sand.

These sediments frequent plant imprints and carbonaceous material. In the middle section the change

was evident from claystone into silty shales, medium light green gray, medium light gray and pale brown,

brittle some fossil with small (0.5 cm) gasteropods. Some shale dark gray, carbonaceous very piritic was

also reported. In the lower section of the formation, the shale became predominantly medium dark gray

brown, silty, brittle. This shale severely caved, in affecting the normal drilling operation and obstructed

the logging of the well.

The Arrayn formation uncomformably overlies the Mirador formation.

Mirador formation

Mirador Formation is the target in Capella-L17 H well. Mirador average gross thickness is about 120ft

and in this area of Capella F location has been divided into Upper Mirador Sand that has three horizons

separated by mudstones thin intervals, and the lower Mirador that is mainly mudstone. Based on

drilling results of Capella-F7 and Capella F10H, the expected lithology is: Unconsolidated sandstones

composed mainly by quartz, predominantly medium grain size, with minor presence of coarse to very

coarse grains, rounded to subrounded, locally subangular, poor sorting. According to borehole image

data, sequence average dips are 6 /90 (azimuth). It occurs intercalated with shale and mudstone.

Cretaceous Fractured conglomerates

Polimictic conglomerate made up of quartz and a notable presence of metamorphic rocks. Very hard,

14

blocky, predominant pebbles and cobbles grain size. Mineral accessories as pyrite, galuconite and mica

are present. Siltstone gray and dark gray, consolidated, blocky to sub blocky, locally laminar.

1.7 G&G TD Criteria

Capella field play is defined as an NE trending anticline fault-bounded (Figure 2). Capella-L17H will

be drilled in the central-south part of the structure, where Mirador Sand shows good reservoir properties

in thickness, porosity and permeability.

Capella-L17H optimal path planning was based on the current knowledge of integrated geological

information from Ombu 3D Seismic, and Capella-L11, Capella-F7, Capella-10H & Pilot, and

Capella-F12ST.

Seismic response in Ombu 3D inline 236 over Capella-L17H is the same over Capella-F10 H at Mirador

level, so is expected similar conditions in this well. Capella-L17 H was planned to navigate up dip in the

west flank of anticline from Capella L location toward Capella F location (Figure 5), through the same

horizon that Capella-F10H (Figure 5).

Figure 5 Time Seismic Inline 236 over Capella-L17H, and Capella-F10H, showing the horizontal well trajectory that was

navigated in the crest of anticline through Mirador Horizon 2 with Capella-F10H and the planned trajectory to navigate with

Capella-L17H in the western flank of anticline.

After drilling Capella-F7, Capella-L11 and Capella-F10 Pilot, were defined three horizon of Mirador

15

Upper Sand (Figure 6, 7 and 8), where petrophysical analysis shows the higher potential in Horizon 2

and 3 of Mirador Upper Sand; Capella-F10H production increasing have confirmed this evaluation. Oil

water contact was found in Capella-L11 at -2159ft TVDss, for this reason Capella-L17H is planned to

navigate higher than OWC at -2159ft TVDss (Figures 6, 8 and 9). Mirador average thickness in these

well is about 120ft, with Horizon 1 average thickness about 25ft, Horizon 2 average thickness about 45ft

and horizon 3 average thickness about 30ft; Mirador base with average thickness about 20ft (Figure 6).

Figure 6 TVDss Well Cross correlation across Capella-L11, Capella-F7, and Capella-F10 Pilot, showing Upper

Mirador with three defined horizons and the Oil water contact at -2159ft TVDss. Capella-L17H will navigate

500 m far away from Capella-L11 to Capella-F7 through horizon 2.

Capella F10 Pilot dipmeter analysis indicates Mirador Formation characterized by piled cylindrical

electro-sequences, with bimodal paleo-stream indicating a flow regime NE SE (Figure 7).

16

Figure 7 Piled channel sequence (Horizons 2 & 3 of Upper Sand Mirador) in Capella-F10 Pilot. Capella-L17H

will stay in horizon 2 while drilling horizontal section

Figure 8 Depth cross section across arbitrary line over Capella-L11, Capella-L17H and Capella-F7, showing

Cap-L17H horizontal well trajectory that will navigate up-flank toward the Southeast in Mirador Horizon 2.

Capella-L17H trajectory will be higher than Oil water contact found in Capella-L11 at -2159ft TVDss

(Vertical scale is different to horizontal scale).

17

Figure 9 TVDss Well Cross correlation showing Capella-L11, Capella-L17 H prognosis, Capella-F7,

Capella-F10H & Pilot and Capella F12ST. Capella-L17H is planned to stay in horizon 2 as Capella-F10H. In

Capella-L11 this horizon was found below Oil Water Contac (Green line in the section) and is the best

producer horizon in existing horizontal wells.

1.8 TD contingencies

Planned TD in Capella L17 H is 5190,2ft MD (3333ft TVD, -2100ft TVDss), however TD contingencies

must be taken into account if while drilling the sequence is muddier than expected.

1.9 G&G Critical Issues related to Objectives and target/reservoir contingency

requirements

G&G Target and objectives critical issues

G&G target is Mirador Sand A at -

navigation in Mirador Sand A interval staying mostly in Horizon 2.

Pilot well will not be drilled to confirm Capella-L17H Mirador Top and Sand A thickness variation in

advance.

Variation of petrophysical properties in Mirador Sand A could be present take at count the variation in

Sand A quality reservoir properties through Capella wells.

18

1.10 G&G Well Evaluation Requirements (logging/coring/sampling)

Open Hole LWD

Horizontal well:

SYSTEM LOG

LOG INTERVAL

TOP

LOG

INTERVAL

BOTTOM

Commentaries

LWD

MFR (Multi Frequency

Resistivity), GR

200ft MD

before Mirador

Prognosis Top

TD

REMARKS:

Geological model will be updated with real data while drilling Capella L17H, therefore prognosis depth

could change. Real depth will be notice for logging plan updating.

Geological Sampling

Two sets of wet samples each 30ft below the 13 3/8

Two sets of dry samples each 30ft below the 13 3/8

Formation Top, from this point samples each 10ft up to TD.

Note: Even though, no samples will be storage for the interval (Surface to 350ft) a description of these

interval must be done every 30ft.

Anticipated testing requirements

The testing program will depend on the analysis of data obtained while drilling the well.

19

1.11 Offset well information

Capella-L17H offset wells are Capella-L11 and Capella-F7 vertical wells and Capella-F10H,

Capella-F12HST, Capella-F13H and Capella-F16H horizontal wells (Figure 10).

Capella-F10H, F13H, F12H and F16H existing horizontal wells path have been oriented toward South and

have been drilled from location F. Capella-L17H path will be oriented in the same direction of F10H,

F12HST, F13H from location L (Figure 10).

Figure 10 Vertical offset wells Capella-F7 and Capella-L11 and horizontal offset wells Capella-F10H,

Capella-F12H, Capella-F13H and Capella-F16H.

20

1.12 Pore Pressure Prognosis

Pore pressure data

Reservoir Reservoir pressure

(Psia) @ (ft, TVDss )

Offset wells used

measurements

from

Data obtained

from Comments

Mirador Sand A 1314 psi -2118 Capella-A1 PBU At 3362 ft

TVD

1.13 Offset Wells Fluid Contacts

Mirador Oil Water Contact in Capella Field was found at -2159ft TVDss based on Capella-L11

petrophysical evaluation.

Possible Fractured Conglomerate oil water contact from Capella logs answers, oil-gas shows and

production test is defined at -2256ft TVDss. This is based on production test results from Capella-F7

well that recorded data in the aquifer, together with gas-oil shows and log interpretation. However,

uncertainty around the Fractured Conglomerate OWC exists with petrophysical evaluation, oil and gas

shows in Capella wells under -2256ft TVDss (Figures 5, 7 and 8).

1.14 Well testing Requirements

Well Production tests requirements

Test Requirement Comments / Purpose

Fluid samples at surface

conditions

Take continuously during test, samples for oil

and water at well head.

Monitoring properties

changes during early

production time (density,

viscosity, salinity, water

and oil samples for full

characterization, etc).

Initial Test / Mirador

/Conglomerate

PCP lifting will be installed and will be

developed the production test, 5 days flowing

period at stable condition. Followed at least 4

days closed. Same test for each zone.

Identify formation

damage, build IPR curve

and plan stimulation jobs

from skin damage

identified. Use pressure

and temperature

downhole sensors, packer

in annulus and check

valve in tubing for good

closure. (Packer will be

used or not after results

ontained from

capella-Z19).

17

2. Drilling Equipment

2.1 Requirements for equipment selection

The drilling depth in Ombu Block is generally about 3000ft ~ 4000ft (TVD), and the maximum

load in drilling operations is about 135klbnet weight in air). Based on the rig load selection

principle and well control equipment requirements, it is determined that the load capacity and

configuration of the rig equipment to be selected should satisfy the requirements for 750hp. Taking

the great load into consideration, before the rig is moved to location, all equipments, especially the

derricks, substructure, hoisting system, rotary system, etc. should be tested and qualified, to ensure

safety of the system when hoisting the maximum casing load with all stands remaining on the drill

floor.

All equipments should be in good condition. Equipment protection and safety devices should be

completely provided. The power and driving system should be efficient. The mud circulating,

cleaning and treatment system should be able to meet the requirements for flow rate, mud property

maintenance and mud storage in different hole sections.

2.2 The Drilling r ig and key equipment configuration

Table 2-1 The Drilling rig and key equipment configuration

No. Name Power & load Number Remark

1 Derrick 375klb 1

2 Crown block 375klb 1

3 Traveling block 375klb 1

4 Hook 375klb 1

5 Swivel 375klb 1

6 Rotary table 375klb 1

7 Drawworks 750hp 1

8 Top drive 250 ton 1

9 Electromagnetic brake 1

10 Mud pump 1000hp 2

11 Diesel engine 810kW 3

12 Generator 320kW 2

13 Double-ram BOP 3000psi 1

14 Killing manifold 3000psi 1

18

No. Name Power & load Number Remark

15 Choke manifold 3000psi 1

16 Driller's console 1

17 Choke control console 1

18 Remote control console 1

19 Surface high pressure

manifold and hoses 1

20 Desander 45kW 1

21 Desilter 45kW 1

22 Shale shaker 2 Derrick2000

23 Degaser 11kW 1

24 Centrifuge 69kW 1

25 Hydraulic tongs 1

26 Mud mixer 7

27 Mud filling device 1

28 Circulating tank 1400ft3 4

29 Mud reserve tank 1400ft3 1

3 Casing Program

3.1 Casing program design

Table 3-1 Casing program design

Casing / liner

description

Hole size

(in)

Casing size

(in)

MD

(ft)

TVD

(ft)

Cementing

section

(ft)

Surface casing 17 1/2 13 3/8 345 345 0 345

Intermediate casing 12 1/4 9 5/8 3891 3298 0 3891

Slotted Liner 8 1/2 7 5175 3333

Note: In the drilling process, intermediate casing setting depths will be adjusted according to the top

of real drilled formations.

19

Table 3.2 Explanations on casing program design

Hole

size (in)

Section TD

(ft MD BRT) Total Depth Criteria

26 Sufficient depth to obtain competent shoe for conductor. (Civil Works)

17 35 Pass through the Quaternary conglomeratic sandstone formation to case

off and confirm enter in the Arrayan sandstone with intercalation of

sand.

35 3894 Pass through Arrayan sandstone with intercalation of sand. Case off the

Mirador Top Formation.

Mirador Formation and unconformity to well TD. Slotted liner

completion

Fig. 3-1 Casing program design schematic

20

4 Well Path Planning

Table 4-1 Well path planning parameters

21

22

Fig. 4-1 Vertical Profile and Plane View of Capella-L17H Plan

5 Requirements for Wellbore Quality

5.1 Hole quality standards in horizontal development well

The survey interval should be less than 300ft in vertical section. MWD should be used to do

real time survey from build section to TVD.

Dogleg rate in vertical section should be less than 2/100ft. Dogleg rate of long radius should

less than 4/100ft in build section and turn section. Dogleg rate of intermediate radius and short

radius should be controlled based on trajectory design.

Wellhead Housing Inclination should be less than 0.5.

23

Table 5-1 Target rectangle

Horizontal section(ft) width(ft) length(ft)

0-1500 6 30

-3000 6 45

6 60

Notes:

If the thickness of payzone is more than 20ft, the width should be less than 9ft.

If the thickness of payzone is more than 15ft, the width should be less than 6ft.

If the thickness of payzone is less than 15ft, the width should be less than 3ft.

5.2 Cementing quality standards

5.2.1 Quality of cement bond

CBL: the relative magnitude of acoustic amplitude is less than 15%, good; less than 30%,

normal; more than 30%, bad.

VDL: the pipe arrivals are no or weak and formation arrivals are clear, good; weaker and clearer,

normal; strong and weak, bad.

5.2.2 Level of cement

The cement should be returned to surface in viscous oil thermal production well.

5.2.3 Effective zones isolation

If isolation length of individual zones is more than 30ft, the effective isolation length should no less

than 15ft. If isolation length of individual zones is less than 30ft, the effective isolation length

should no less than 50% isolation length. If isolation length of individual zones is less than 5ft,

these zones are treated as one zone.

5.3 Casing pressure test

Table 5-2 Casing pressure test

Casing size Production well Injection well Gas well Pressure drop

allowance

2000psi 2000 3000psi 3000psi 70psi/30min

9- 10- 1500psi 1700psi 2000psi 70psi/30min

24

6 BHA Program

BHA configuration for this block should be determined based on BHA optimization concept. In

actual drilling operations, BHA can be adjusted in time according to characteristics of formations

being encountered. The selected BHA should be compatible with the formation to improve ROP and

realize the objective of drilling operations

6.1 Proposed BHA for each hole section

Table 6-1 Proposed BHA for each hole section

No Section

(ft) BHA

1 0 350 17 1/2 Bit+8 DC2+17 stabilizer1+8 DC4+5 DP

2 3891 12 1/4 Bit+8 1.5PDM 1+8 MDC1+8 LWD+ NMDC1

+5 + drilling jar1+5 HWDP21+5 DP

3 5190 8 1/2 Bit+ 1.5PDM 1 MDC1+ LWD+6

NMDC1+5 + drilling jar 1+5 HWDP21+5 DP

6.2 Drill string strength check data

Table 6-2 Strength check data of drilling tools

Depth of neutral point

(ft):3275 Location of neutral point: 5 OD DP

Strength Check Data

Spud

No.

Name

of

drilling

tools

OD

(in)

thickness

(in)

Steel

grade

Weight

(lb/ft)

Length

(ft)

Yield

strength

( lb/in2)

Tensile

coefficient

Torsional

coefficient

MISES

coefficient

1 HWDP 5 1 48.63 885.82 35.54 14.52

2 DP 5 0.362 G-105 19.5 3939.7 105000 28.26 15.83 5.11

7 Drill Bit Program recommendation

Based on bit type selection methods, formation rock characteristics in Capella Block and

drilling data from offset wells in this area, bit types are selected properly and hydraulic

parameters are designed exactly to achieve the objective of improving ROP, increasing bit

footage and reducing drilling cost.

In the drilling process, bit type can be adjusted in time according to actual bit application on site

and the experiences of contractor.

25

7.1 Bit type selection recommended

Table 7-1 Bit type selection program

No Formation Size

(in) Bit Quantity

section

(ft)

footage

(ft)

1 Q A 17 1/2 HAT127 1 350 350

2 A M 12 1/4 PDC M316 1 3894 3544

3 M 8 1/2 PDC M316 1 5190 1296

Note: In the drilling process, bit type can be adjusted according to actual conditions on site.

7.2 Drilling parameter recommended

Table 7-2 Drilling parameter recommended

Bit

ord

er

Fo

rma-

tion

Hole

section

(ft)

Nozzle

(mm)

Drilling parameters Hydraulic parameters

WOB

(kN)

RPM

(r/min)

Flow

rate

(L/s)

SP

pre.

(MPa)

Bit

PD

(MPa)

Circ.

PD

(MPa)

Impact

(kN)

Jet

vel.

(m/s)

Bit

HP

(kW)

Spec.

HP

(W/mm2)

Annu.

vel.

(m/s)

Power

usage

( )

1 Q A 0 350

2 A M 3894 12,12,

12,12

60

100

120

180 48 17.72 2.22 15.51 1.08 73.47 44.22 2.42 1.38 36.85

3 M 5190 10,10,

10,10

60

80

100

120 30 21 3 7 1.3 81 39 2.1 1.1 32

Note: Data in the table are theoretically calculated values that can be adjusted properly on site according to actual operating conditions.

SP pre.=Stand pipe pressure; Bit PD=Bit pressure drop; Circ. PD=Circulating pressure

drop; Jet vel.=Jet velocity; Bit HP=Bit hydraulic power; Spec. HP=Specific hydraulic

power; Annu. vel.=Annular velocity.

8 Drilling Fluid Program

8.1 Guidelines for drilling fluid application

Drilling fluid type: High quality water based drilling fluid will be used.

Drilling fluid properties: Based on formation pore pressure and collapse pressure and

according to actual drilling conditions, adjust drilling fluid properties properly and perform

near-balanced drilling.

The Mirador formations are prone to sloughing and tight hole. The drilling fluid should have

good inhibiting property and sloughing resistance and can maintain reasonable rheological

property to clean the wellbore. While drilling in reservoir, pay more attention to reservoir

26

protection.

While drilling in the reservoir, observe changes of drilling fluid properties carefully and adjust

drilling fluid properties in time. It should be noted that don't weight drilling fluid blindly to

avoid fracturing and contaminating the reservoir.

In drilling horizontal section, the drilling fluid should have good lubrication, good rheology for

cuttings carrying out.

8.2 Drilling Fluid Design Principle

Drilling fluid application should be beneficial to discovering and protecting the reservoir, to

collecting geologic data, to fast and safe drilling, to removing oil & gas, to preventing and

treating complex downhole troubles and to environmental protection.

Formations to be encountered in this well are prone to sloughing, lost circulation and pipe

sticking. Therefore, drilling fluid should be able to resist sloughing, lost circulation and have

the capacity of protecting the reservoir.

Drilling fluid design for this well is conducted according to ctual drilling data from offset wells.

The main purpose is to discover and protect the reservoir by performing near-balanced drilling.

8.3 Drilling fluid systems and basic formulations

According to characteristics of formations to be encountered in Capella Field, drilling fluid should

maintain low solids and lower filter loss and have good inhibiting and rheological properties to

ensure safe and fast drilling. The key is to protect the reservoir.

8.3.1 Drilling fluid systems

Table 8-1 Drilling Fluid Types for Each Hole Section

No Hole Size in Section ft Mud type

1 17-1/2 0 350 Bentonite+Fresh water

2 12 1/4 350 3894 Inhibitive polymer anti-collapse+Lubricator

3 8 1/2 3894 ~ 5190 Low density - No solid polymer + shielding protection material.

27

8.4 Design of drilling fluid properties

Table 8-3 Drilling fluid property for each hole section

Properties Drilling fluid properties

0 350 ft 350 3894 ft 3894 5190 ft

Mud weight ppg 8.8 9.0 9.2 10,3 8.6 8.8

Funnel viscosity sc/qt 40 - 50 50 60 50 - 70

API Fluid Loss cc N/C 3- 6 3- 5

Gels lb/100

ft2 4/6/9 7/15/20 4/6/9 7/10/15

pH 9.0 9.5 9.0 9.5

Yield point lb/100

ft2 15 20 15 - 20

Plastic viscosity cp 15 18 11 - 16

Solids %

28

Table 8-5 Solids control equipment and application requirements

Hole

section

Solids index Shale shaker Desander Centrifuge

(ppg)

Cs

(%)

Solids

content

(%)

Mesh

Running

time

(%)

Treating

volume

(gal/min)

Running

time

(%)

Treating

volume

(gal/min)

Running

time

(%)

8.8 - 9.0

1 9.2 10,3 6 8 >60 100 880 100 264 100

8.6 - 8.8 1 >60 100 680 100 264 100

8.7 Requirements for Drilling Fluid Test Instruments

Drilling fluid test instruments should be provided as listed in the table below to ensure that drilling

fluid properties can be tested and maintained in time on the rig site. All instruments should be

calibrated before sending to the rig site and they should also be often calibrated when they are in

use to enshure the accuracy of the measured data.

Table 8-6 The least offering of drilling fluid test instruments

Name Quantity Name Quantity

Drilling fluid densimeter 2 MBT measuring equipment 1

Marsh funnel viscosimeter 2 Stopwatch 2

6-speed rotary viscosimeter 2 Alarm clock 1

API medium pressure filter press 1 Electric mixer 2

Solids content tester 1 Electric stove 2

pH-meter or pH indicator strip 2 Timer 1

Mud cake friction meter 1 1000ml mud cup 10

Sand content tester 2 Filtrate analyzer & tester 1 set

8.8 Requirements for Drilling Fluid Management on the Surface

Requirements for killing fluid reserve system are: The reserve volume should meet the given

demands and the killing fluid can be pumped directly to the circulating system.

Storage tanks should be provided as required for reserving killing fluid. Two long- shaft mixers

operating normally should be installed on each storage tank. Storage tanks should be connected

with the lines for the short way circulation and the killing fluid should be able to be pumped to

the circulating system directly.

It required that each circulating tank of the surface circulation system should be provided with two

mixers and the drilling fluid gun will work normally.

Rain & water protection facilities should be provided for the circulating, reserving and weighting

29

systems.

It is required that an additive make-up tank with the volume of no less than 350ft3 should be

provided, and the mixers should meet the demands of making up the additives.

To meet the demands of curing the losses, it is required that a LCM tank with two mixers should be

provided whose volume is 530 700ft3.

Drilling fluid materials should be stored in a special room. If they have to be placed in the open

air, pads and covers should be used to protect them from rain and moisture. Drilling fluid

should be treated on the basis of test results to prevent downhole troubles or accidents resulting

from improper treatment.

The bottom of the waste liquid pit and the cuttings pit should be lined with impermeable

materials to avoid seepage of polluted water and prevent cuttings from piling up directly on the

ground.

9 Cementing Program

9.1 Guidelines for ensuring cementing quality and oil well life

Try to control hole enlargement ratio within 10% and prevent very irregular borehole.

Casing centralizers should be placed properly. While running casings in hole, note to move

casings and ensure they are in the center of the wellbore.

On the premise of ensuring borehole safety, try to increase cement injection rate and improve

displacement efficiency.

Reasonable cement slurry system: Select low filtration, sand-cement slurry. Control free water

in the cement slurry to zero and water loss to less than 100ml to improve thermal stability of the

cement slurry.

Ensure continuity of the cementing operation.

9.2 Selection of Cementing and Completion Technologies

9.2.1 Requirements of cementing and completion

Height of the cement plug within the casing should conform to the design requirement.

All the drilling fluid within the annular space of the cemented interval should be displaced by

cement slurry. No drilling fluid is allowed to be left.

Cement sheath between the casing and the borehole wall rock should have sufficient cementing

strength that can withstand the impact of the pipe string being run in hole.

After the cement is set, no oil, gas and water should flow out from outside the casing and there

30

should be no channeling among various pressure systems in the annulus.

The set cement should withstand invasion of oil, gas and water for a long period of time and the

effect of high temperature.

9.2.2 Selection of cementing and completion technologies

Completion method will be selected based mainly on characteristics of reservoir rock, reservoir

features and requirements of oil production technology in order to reduce reservoir damage,

improve production capacity and prolong oil well life. Cementing selection as follow.

Surface casing using conventional cementing.

Production casing using screen top cementing, cement plug return to surface.

Table 9-1 Basic Parameters for Cementing and Completion

Spud

No.

Hole

size

(in)

Casing

size

(in)

Casing

setting depth

(ft)

Cement

returning

depth

(m)

Cementing &

completion

mode

Remark

1 17 1/2 13 3/8 345 Surface Conventional

2 12 1/4 9 5/8 3891 Surface Conventional

3 8 1/2 7

Slotted liner from

3741 MD to

517

9.3 Casing String Design

9.3.1 Casing string design principle

Casing design is to ensure that the maximum stress on the casing in all the life time of the well is

within the allowable safety range so as to protect the oil & gas well. The design principle is as

follows:

Requirements for drilling, production and payzone modification technologies can be satisfied.

In casing design, the influences of collapse, burst and stress changes in the process of

exploitation should be taken into consideration. The balance between casing strength and casing

string mechanics should be established. To ensure that safety is put on the first place, casing

design consideration is based on the assumption that the casing is in the most dangerous

downhole condition.

Safety factors for casing string strength design are as follows. Collapse resistance: 1.125, burst

resistance: 1.125, tensile: 1.8.

On the premise of meeting strength requirement, the cost should be as low as possible.

31

9.3.2 Casing string design and strength check

According to drilling & development program for this Block, in casing selection, besides meeting

strength requirements, the influence of the casing on oil well life should also be taken into

consideration. Casing string design is shown below.

Table 9-2 Casing string design and strength check

Casing /

liner

description

Casing

size

(in)

MD

(ft)

Steel

grade

Wall

thickness

mm

Thread

Unit

weight

(lb/ft)

Safety factor

Tensile

St

Collapse

Sc

Burst

Si

Surface

casing 13 3/8 345 K55 10.92 BTC 61 31.45 7.92 11.78

Production

Casing 9 5/8 3891 N80 8.94 BTC 43.5 6.71 9.05 5.74

Slotted

liner 7 5175 N80 10.36 BTC 29

Note: a. Casing strength designs are calculated based on formation pressure data provided by the

geologic design. Cementing design should be proved again on site according to actual

conditions.

b. All casing collapse strengths are calculated based on 100% empty casing. c. Threads of all casings are required to be coated with high temperature thread sealant. d. Related cementing tools and accessories must match the threads of casings. Their strength

should not be less than that of the casings in the specific hole section. Enough short casings

with variable, threads should be got ready.

Table 9-3 Casing data

OD

In Steel grade

Wall thickness

mm

Thread

type

Unit weight kg/m

(lb/ft)

Tensile

strength

klbs

Collapse

strength

psi

Burst

strength

psi

13 3/8 K55 10.92 BTC 61 962 1.540 3.090

9 5/8 N80 8.94 BTC 43.5 1005 3810 6330

7 N80 10.36 BTC 29 676 7,020 8,160

9.4 Cementing pipe string design

Table 9-4 Cementing pipe string design

Spud

No.

Casing size

in Cementing pipe string

1 13 3/8 float shoe +casing string +landing joint

2 9 5/8 float shoe +1 casing+float collar + casing string +landing joint

3 7 Shoe + pup joint of sloted liner + Ring seal sub + Sloted liner + thermal

extention loint + Liner hanger

32

Fig. 9-1 Three Phases

9.5 Selection and placement of centralizers

Spring centralizers will be used. In the reservoir section, one centralizer is placed every 2

casings, and in other hole sections, one centralizer is placed every 4 casings.

Centralizers will be placed per API Standards to ensure that casings will be run in hole

smoothly and be centralized.

9.6 Cement Slurry Design

9.6.1 Cement slurry design principle

Properties of the cement slurry must be stable under downhole temperature and pressure.

The cementing slurry should be set and reach the specific strength within the fixed WOC time.

The set cement should have very low permeability.

33

9.6.2 Selection of cement slurry

The cement slurry system with low water loss will be selected to improve thermal stability of

the cement sheath, adding quartz sand to cementing slurry by 30~40%.

Additives such as water loss reducer, defoamer, dispersant, etc. should be added. Additives to

be used should satisfy the requirements of cement slurry properties, ensuring operation safety

and cementing quality and benefiting reservoir protection.

9.6.3 Requirements of cement slurry properties for the reservoir

Cement for oil wells must be tested carefully before use to check its properties. Properties of

cement slurry with additives should be tested, including tests on density, thickening time, free water

and rheology, tests on tensile strength of the cement bond as well as tests on compatibility of the

cement slurry with the preflush and drilling fluid.

Table 9-5 Cement slurry property parameters for the reservoir

Properties Property requirement Remark

Density (g/cm3) 1.90

Rheology cm 25cm

Water loss ml 100ml/1000psi 30min

Free water content ml 0

Thickening time h Total cementing time +1h

Tensile strength 24hr 2000psi

9.6.4 Cement volume calculation

Table 9-6 Cement volume calculation

No Size

(in)

Cementing

section ft

Cementing

type

Slurry

Type

Density

(ppg)

Enlarge

rate of

caliper

Excess

cement

Quantity

(klb)

1 17 1/2 0 350 Inner string

stabbing

Class

G 15.4 15 50 98

2 12 1/4 0 2791

Cementing

above the top

of Screen

Lead

Class

G

13.6 10 80 118

12 1/4 2791 3891

Cementing

above the top

of Screen

Tail

Class

G

15.4 10 80 47

Note: Cement volume and cement returning depth are theoretical data which should be revised in

operations according to measured data.

34

10 Reservoir Protection Program

The drilling fluid system that is compatible with the reservoir will be used and drilling fluid

properties should be controlled to reduce formation contamination as much as possible.

Measures to be taken are as follows:

a. Polymer drilling fluid system will be used to reduce and prevent harmful substances from

invading the reservoir.

b. Control the low density solid content in the drilling fluid and avoid solids from migrating

and damaging the reservoir.

c. For drilling fluid used in the payzone section, API filter loss is controlled to 5cc. Prevent

water sensitivity effect from damaging the reservoir.

Adopt the shielding & temporary plugging technique and use kerite additives to prevent

harmful substances from invading the reservoir.

Perform near-balanced or underbalance drilling technology. Predict formation pressure in time

and adjust drilling fluid density correspondingly. According to related technical regulations, the

additional density is controlled to 0.42-0.83 ppg in the reservoir and to 0.58-1.25ppg in the gas

zone. While tripping out of hole, the effective hydrostatic pressure in the wellbore should be a

little greater than or equal to that of the formation pressure.

Keep stable rheological property of the drilling fluid and avoid too great changes. It should be

ensured that while drilling in the reservoir, all properties are always conformable to the

requirements of reservoir protection and borehole stability.

Control tripping speed to avoid pressure surge and reduce contamination to the reservoir.

If it is required to weight the drilling fluid while drilling in the reservoir, use the weighting

materials that can be acidized and dissolved.

35

11 Well Control Program

11.1 Selection of well control equipment

Select pressure ratings of the well control equipment according to the predicted formation pressure

of Capella oilfield. The BOP selection program is shown in Table 11-1.

Table 11-1 Wellhead equipment and pressure testing requirments

Spud

No. Name Type

Testing requirements

Test

pressure

(psi)

Pressure

holding

time

(min)

Al lowable

pressure

drop

(psi)

1 Simple wellhead

2

Casing head T 10 3/47-21(3000psi) 3000 10 100

Double ram 2FZ 28-21(3000psi) 3000 10 100

Choke/kill

manifold JG-21/YG-21(3000psi) 3000 10 100

Figure11-1 Wellhead equipment for 1 hole section

36

Figure11-3 Wellhead equipment for 12 1/ hole section

Figure11-3 Wellhead equipment for 8 1/2 hole section

37

Figure 11-3 21MPa choke/kill manifold

11.2 Requirements for BOP System Inspection and Testing

Requirements for testing well control equipment should conform to regulations of the Industrial

Standards.

The BOP system includes BOPs, spool, choke/kill manifold, control system as well as liquid

and gas lines. The tubular & tool company will be responsible for inspecting them piece by

piece and making tests on them per requirements. When all pieces of equipment is qualified, fill

in the qualification certificates, check the test records, sent the equipment to the rig site and

hand them over to the drilling crew. All threads should be well protected during transportation

to prevent them from damage.

The whole set of well control equipment will be tested in the well control workshop with fresh

water. The ram BOP will be tested to rated pressure for at least 15 minutes. Pressure drop is

allowed which should not exceed 100psi for the ram BOP.

Before drilling in the reservoir and after replacing the parts of well control equipment, make

tests again with blanking plugs or pressure test plugs.

For testing the choke/kill manifold, the test pressure for all valves before the choke valve is the

same as that for the ram BOP, and the test pressure for all valves after the choke valve is one

pressure rating lower than that for the ram BOP. When testing each valve, all valves before and

after it should be opened. Only after testing, can all valves return to required standard on/off

position. Various internal blowout prevention tools should also be tested to rated working

pressure.

38

11.3 Installation of the BOP System

11.3.1 Installing the wellhead components

Installing the spool. Holes in both sides of the spool should face both sides of the derrick door.

Installing ram BOP. Hand wheels of the manual locking device and the control rod should be

located on both sides of the derrick door. Outlet of the side flange will face the direction of the

derrick door. According to the size of the drilling tool to be used, install pipe rams with

corresponding size. Put plates marking the types and sizes of the rams in the driller's console

and in the remote control console in order to avoid wrong closing when blowout occurs. The

manual locking device should be completely installed and well connected, and a plate marking

the number of turns should be put on the hand wheel.

Relief manifolds will be installed on both sides of the derrick. The choke manifold will be

installed on the right of the derrick (the drilling fluid outlet side), and the kill manifold will be

installed on the left of the derrick. The relief/choke manifolds should be unblocked and be

secured by cement base. Distance between the outlet of the manifold and the wellhead should

be no less than 250ft.

After installation of the BOP system, adjust the crown block, the rotary table and the BOP stack.

Centers of them should be aligned vertically and the offset should be no more than 0.4in. After

adjustment, fix the BOP stack to the substructure with wire ropes.

11.3.2 Installing the control system

The remote control system (i. e. the accumulator) should be installed in a place about 100ft

away from the wellhead, usually in the diagonal direction of the derrick. The remote control

system should be installed in a skid-mounted prefabricated house. Ditches for draining water

will be dug around the house. Oxygen bottles and combustibles are not allowed to be placed

near the house.

The driller's console (i. e. the main control panel) will be installed on the drill floor close to the

driller's working post for the convenience of the driller's operation.

Installing the pipelines. Before installing the hydraulic and air pipelines, each pipe should be

cleaned by compressed air and be connected correctly as required. When connecting the air

lines, the air valve and the air bypass valve of the air pump should be closed which can only be

opened when they are to be used. All pipes should not be bent, broken and fired. They should be

put in order and be well fixed. The control lines should not be used for welding and other

purposes.

39

Connecting the electrical lines. When connecting the electrical lines, check again to see whether

electric parameters are correct. The electric power supply should be connected before the main

switch on the rig site and be controlled with individual switches, so that when electric power of

the rig site is turned off due to occurrence of a blowout, the use of the control system will not be

affected. Electrical lines for the transceiver and long-distance search lights should also be

connected before the main power supply.

11.3.3 Test-run of the BOP system

Before test-run, check all connections of the pipelines to see whether they are connected

correctly.

Make test-runs with and without load respectively. Check leackage of all connections and

working conditions of all valves and pipelines. Solve the found problems in time after pressure

is released.

Open and close BOPs and relief valves twice by trial to see whether the switches are in good

working condition.

12 Operation Guidelines for Each Hole Section

12.1 Pre-spud preparation and site construction

The length of the front field is at least 150ft. Requirements for enough rig site area for special

operations shall be satisfied.

Foundations for the derrick, diesel engines, mud pumps and the tanked circulating system shall

be firmly fixed. Ensure high quality of the bottom construction and the height difference of

basic planes is less than 0.12in.

The effective capacity of the mud reserve tank is no less than 8500ft3 and water reserve tank

no less than 17500ft3 should make use of plastic cloth to prevent water rush and seepage and

meet application requirement. There should be no buildings except the dog house and other

facilities within the overturning radius of the derrick.

Equipment should be installed flatly, stably, smoothly, completely, firmly, effectively and

properly according to specifications to ensure the quality of installation. The crown block,

rotary table and wellhead shall be calibrated to make sure that they are aligned, and the

deviation should be no more than 0.4in.

Requirements of circuit installation: electric power for drill floor lamp, derrick lamp, engine

40

room lamp, pump room lamp, dog house lamp and dormitory lamp, search light, motor circuit

and alarm circuit should be transmitted through nine separate power lines and be under

centralized control in the dog house.

Lighting equipments of drilling fluid tank, derrick, engine room and pump room should be

safety, explosion-proof, in good condition, no electrical leakage, no fire spark. Power house

should be equipped with lightning arrester.

Search lights of well site and storage tank/pool should be enough to meet the lighting

requirements for rig site operations.

The capability of water supply equipment shall be higher than 700ft3/h. The maximum water

supply capability of pool or tank shall be higher than 3500ft3/h.

The ground surface under the drill floor and pump room or places around the rat hole and

mouse hole must be faced with cement to avoid water seepage into the base which affects the

base safety.

The ground surface under the drill floor, engine room and pump room should be higher than the

rig site surface and available with external drainage. Ditches shall be dug for draining off water

and be connected to the sewage pit whose effective volume is no less than l00m3.

The well site should be flat and smooth. All the drill tools should be steadily placed on pipe

rack. Disordered placement is strictly prohibited to avoid drill tool accidents caused by surface

damage.

Before spud, all the power and mechanical equipments should be tested run for 2h with load.

Ensure that oil&water&gas lines are sealed and the switches of valve are flexible without

leaking. Do not spud until all things are qualified.

Prior to drilling operation, the drilling crews should be convened to understand clearly the

geologic and engineering design and complete all preparatory work with definite guiding

ideology.

17 1/ hole section

Ensure that the hole is vertical. WOB increases with the weight of drill collars in the given

range. Trip out and measure the hole angle. Drilling operation is not allowed until successful

measurement of the hole angle is achieved.

Run in 13 3/ casing and cementing

a. When running casings, threads of the casings should be tightened to specified torque.

Prohibit thread alternating, undertonging and electric welding between threads. If there is a

41

symbol at the pin end of casing, screw on the thread of the casing to the bottom line of

the symbol and fill up casing with drilling fluid.

b. When running casings, bind float shoe, float collar and intermediate casing with thread gum.

If thread gum is unavailable, joint them with electric welding.

c. Cement slurry must return to surface.

Properly select BHA. Check the weight indicator. Start drilling with light WOB and keep the

borehole vertical. The hole angle should be smaller than 0.5, otherwise take measures to

straighten the hole.

Add stabilizers with is matched with the bit diameter at the upper part and lower part of the first

drill collar to ensure a regular borehole and successful casing job.

Make up connections quickly, make good control of running in

too fast. Drill string should be reciprocated when circulation stops due to some reasons to

prevent pipe-sticking. The time drill string stay in hole should not exceed 5min.

12.3 12 1/4 hole section

Safety measures

a. Check the equipment in advance to ensure continuous operation and avoid interrupted

operation.

b. Feed WOB evenly, drill the soft and hard interface successively and make up connections

quickly. Keep the pump working for a long time (start early and stop late. Variation of flow

rate should be smooth.

c. The drill bit should contact the bottom hole steadily. Make a survey before tripping out of

the bit or after continuous footage of 500ft for each bit. If the hole angle is a bit larger,

replace the current BHA with deviation-correction BHA.

d. Make good control of tripping speed. Find drags or pipe-sticking timely and treat them in

accordance with operation specification.

e. Drilling fluid should be maintained and treated in accordance with the design requirements.

Corresponding LCM should be reserved on the rig site. Enough high quality drilling fluid

should be stored at site according to design requirements.

f. Prevent anything from falling into the borehole.

Raise the mud inhibitive capability, mud must have good functions of hole wall protection and

hole cleaning.

In drilling this section, flow rate should be higher than 700gpm, pay more attention of cuttings

bed, recommended short tripping or backreaming per 24hours. Precaution the differential

42

pressure sticking pipe or casing.

Prepare the casing accessories and cementing tools to realize cementing above the top of screen.

One kind of BHA to realice trajectory of building up, turning direction, holding on and

horizontal sections

Bit bouncing, deviation trend, lost circulation and drill tool accidents are problems encountered

in drilling operation. Therefore, appropriate drilling technology should be worked out in view

of the feature of the drilling interval. The key concerns are to keep a vertical borehole, drill

rapidly and do well in near-balanced drilling and trajectory controlling.

Strengthen management of equipments especially the drill pump. Normal operation of drilling

equipment should be assured and prevent operations from being interrupted frequently.

Before the drill collar drilling out the surface casing shoe, WOB should be controlled in the

range from 10klb to 18klb. The second gear should be used for drilling. After the drill collar

drilled out the casing shoe, WOB should be gradually increased to 60klb to 80klb. Avoid

borehole deviation and ensure the wellbore quality.

Survey the hole angle before tripping out or after drilling every 1000m to 1500ft in order to

monitor and follow the hole trajectory timely.

During drilling process, pay attention to the downhole situation. If borehole wall sloughing is

encountered, adjust drilling fluid properties timely to ensure normal downhole operation.

Prevent downhole problems and accidents caused by borehole wall sloughing and lost

circulation.

Before spudding, all equipments especially the electric circuit part and well control equipment

shall be inspected completely. Strictly perform the blowout prevention drills to achieve the

control of well head in each shift. At the same time, engineering and geological technical

personnel should inform drilling crews of technology details for drilling the oil and gas

reservoir. The post responsibility system should be implemented.

Drill tools should be strictly managed. Carefully check the drill tools to be run in hole. Persist in

switching within the drillstring and check thread alternating to avoid drill tool accidents.

Operators should strengthen the sense of responsibilit y and observe and analyze down hole

situation in time. In case the pump pressure drops, stop drilling to analyze the reason. If no

reason can be searched out, put out of hole and check.

Persist in making good use of solids control system. Add appropriate amount of lubricant to

control the frictional coefficient of mud cake in the designed range. The time of drill tool being

static in hole should not exceed 3min to avoid pipe-sticking.

Strictly inspect the rig tools. Prevent anything from falling into the borehole to avoid

43

pipe-sticking.

12.4 8 1/2" hole drilling

Solids should be controlled as lower as possible.

Change mud by new clean mud, reduce the mud weight and other properties to design

Pay more attention to the differential pressure sticking pipe and casing

Adopt the shielding & temporary plugging technique to prevent harmful substances from

invading the reservoir. Prepare different types and parcels of LCM on the location.

In drilling this section, flow rate should be higher than 500gpm, especialy in horizontal section,

pay more attention of cuttings bed, recommended short tripping or backreaming per 24hours.

Precaution the differential pressure sticking pipe or casing.

MWD/LWD tools should be in good condition. Before running in hole test them carefully on the

surface or in shallow depth of the hole.

The dogleg should be controlled within permit rang. Real well trajectory should follow the design

one and keep the trajectory smooth.

12.5 Precautions for drilling hazards

12.4.1 Leak protection

During drilling process, adjust drilling fluid properties. Select the designed lower range value of

drilling fluid density if possible to keep near-balanced drilling.

Before encountering the leakage interval, lost circulation materials should be prepared in

advance. Condition drilling fluid properties in accordance with design requirements and prepare

to add lost circulation materials at any time.

When running in hole, the running speed should be under control. After drill to 1500ft, auxiliary

brake should be used. The time for running in a stand should not be less than 30s to prevent

inducing drilling fluid loss because of the excessive high pressure surge caused by the excessive

high speed.

If weighting operation is needed with active oil&gas during drilling process, density should be

gradually increased according to the circulation. It should be increased 0.4 to 0.8 ppg for each

circulation cycle until the overflow disappears. Prevent downhole situation becoming complex

caused by blindly weighting operation.

During running in process, circulate drilling fluid in stages. Running in to the bottom directly

and then starting pump to circulate is strictly prohibited. Start pump with a low flow rate to

44

push through the hole, and then pump with normal flow rate. Strictly prevent leakage caused by

opening pump too fast.

Designated personnel shall observe the changes of drilling fluid level at all times. In case lost

circulation occurs both when drilling in and running in, pull out of hole at once if leakage

volume up to 180ft3. Continuously pump drilling fluid to the hole and prepare for loss-curing.

12.4.2 Well trajectory control

Equipment should be installed flatly, stably, smoothly, completely, firmly, effectively and

properly according to specifications to ensure the quality of installation. The crown block,

rotary table and wellhead shall be calibrated to make sure that they are aligned, and the

maximum allowable deviation should be no more than 0.4in.

Make sure that the weight indicator, parameter recorders and pressure gages are sensitive,

accurate and in good condition.

Before running in MWD/LWD tools, they need to be tested on the surface, when running in

hole in shallow position, do test again to ensure they are in good condition.

When drilling in surface layer, keep balance of the drilling hose. Drill with low WOB. The hole

deviation angle should be less than 0.5. Well straightening operation should be performed if

hole deviation angle is too large.

When maintaining equipments or treating drilling fluid, reciprocate the drill string by a wide

margin to circulate drilling fluid. Rotational circulation should not be in a position with a high

flow rate for a long time to avoid deviation caused by a large hole.

A new bit should not be drilled to the bottom without break. Start pump with low flow rate

when near the bottom. Start rotary table with bottom gear for slowly running to bottom. After

running the bit with 10-40klb WOB about half an hour, WOB should be gradually increased to

normal value.

While drilling in, strictly control the borehole quality to meet the requirments of designed well

profile.

12.4.3 Pipe-sticking prevention

When drilling horizontal section, differential pressure sticking pipe and casing will easily

happen, the efficient prevention ways should be taken.

Short tripping and backream need to be used every 24 hours or 800ft to keep the hole in good

nd

sticker. In this situation, pay more attention to pipe sticking when run in hole with drill string.

45

For hole cleaning, circulation time should be more than two bottoms up. In high deviation hole,

cuttings often settle down, flow rate should be kept as high as possible, meanwhile, raise the

rotating speed properly. Drill string in static in the hole is no more than 3 minutes whatever

operations carry out.

Once the differential pressure sticking happen, try to keep circulation at any time. Prepare

release agent and soak the pipe as quickly as possible. To reduce differential pressure the weight

of release agent need to be as low as possible.

Before running in E-logging tools or casing, ream the hole thoroughly. Rock bit and slick

collars is the best string used to ream the hole. Increase flow rate as possible; observe the

cuttings return till no cuttings on the shale shaker.

when casings are running in horizontal section. Run casing to the bottom as quickly as possible,

and then circulate mud for cementing.

Well trajectory need to be controlled in good profile, high dogleg will produce high resistance.

Montor well profile to evaluate this resistance; take the right way to run casing to the bottom.

Prior to spudding in, rig equipments, well head, instruments should be inspected by relevant

personnels from company. Equipment should be installed flatly, stably, smoothly, completely,

firmly, effectively and properly according to specifications. Drilling operation can not be

performed until meet the acceptance requirements.

Inspection requirements before every spudding in

a. The driller should inspect wear information of the drilling line. Slip and cut off the drill line

if there are 12 broken wires in a pitch of strand.

b. The driller should carefully check the brake system, fixation condition at the both end of

drilling line and the regulating situation of the brake band adjusting screw.

c. Inspect whether the weight indicator is accurate, whether the hang weight conform to the

actual weight of drill tools, whether the curve of auto recorder is clear and whether have

abnormal records.

d. Carefully check whether gas circuit and crown block saver are reliable.

Strengthen the movement of drill string. The time drill string being static in hole should not

exceed 3min. If drill ing operation can not be performed, move drill string up and down by a

wide margin.

If drill string can not be moved because of equipment failure, 2/3 of the hang weight should be

pushed slowly to the bottom hole. Repair the equipment as soon as possible. After repairing the

equipment, circulate drilling fluid to pull out of hole rather than drill ahead.

46

Make up connections quickly. Especially at the time of faster penetration, the time make a

connection should not be more than 3min. Pump stop time should be cut down (stop pump late

and start pump early) to reduce the settle sand.

Condition drilling fluid before drilling in. Circulate with high flow rate and pull out of hole

after at least 2 bottoms up. Running operation to hole bottom should not be performed in one

time. Start pump to circulate stepwise and run in hole until normal. Do not force to pull up or

run in with too more weight for a tight hole over 225klb. Make connection with a Kelly, start

pump to push through the hole and circulate to normal, then go on tripping.

When drilling in, if pump pressure raise, hang weight drop, returned drilling fluid volume

reduce and rotary table reverse occur, stop drilling ahead or making connections. After pulling

drill tool to normal interval, borehole should be returned to normal by flushing, making wiper

trip and reaming to precede operation.

In water swelling formation or unconsolidated formation, condition drilling fluid properties and

control water loss to avoid drags and stuck pipe caused by tight hole, hole sloughing or thicker

mud cake.

Footage of every bit should not be more than 1000ft. Otherwise, make short trip to ensure a

smooth hole. The length of trip interval should be longer than that of drilling interval to prevent

drill pipe sticking in mudstone due to tight hole.

If pump pressure drop is found when drilling in, stop drilling ahead to find the reason. If any

problem can not be found on surface, pull out of hole to inspect drill tools.

During drilling process, if drill time decreases, bit bouncing, pump pressure raises and

pipe-sticking when picking up drill tool are found, stop drilling at once to condition properties

of drilling fluid. At the same time, move drill tool up and down for long distance with high

speed rotation, increase the circulating capacity to remove ballings on bit or stabilizer.

If bit balling occurs, the bottom gear should be used for tripping out. Fill up drilling fluid

continuously. If drilling fluid can not be filled in the annular space, fill in from drill tools. The

tripping speed should be not too high to prevent down hole problems caused by swabbing.

Prevent anything such as tools, screw and dies from falling in hole while operating at the

wellhead. While the well is empty, bit box can be used to cover the wellhead.

Drill tools to be run in hole should be carefully inspected according to regulation. Drill tool

should not be run in hole if unqualified.

47

13 Wellhead equipment for completion

13.1 Casing head specification

T 9 5/8 7 -21 (3000psi). The last casing head should be below the ground for the convenience of

rig quick moving. Consider about the top level of casing head, it must be keeped as the same level

as ground

13.2 Wellhead protection

Keep the cellar clean.

The casing head must be kept horizontal with a level ruler. After installation of the wellhead,

tighten the four conners of the well head with guys and align the casing head with the center of

the rotary table.

Two sets of casing head wear-proof casing must be available. Install one set during operation

and check and replace it periodically. Supplement immediately if no backup equipment is

available.

All flange and handwheel must be made up to the specified torque, wellhead cap must be

installed before installation of the the Christmas tree.

Carry out sealing compound injection and pressure test operation in accordance with

regulations to ensure reliable sealing.

13.3 Completion requirements

Drift the hole to the artificial hole bottom with standard drift diameter gauge and testing drift

diameter gauge.

Tally the tubing being run into the hole and make records based on running sequence.

There should be no oil, gas and water invasion into the casing or leaking out of the casing after

completion.

Upper end surface of the top flange (lower end surface of the tubing spool) for casinghead

hanging the production casing can not be 1.3ft higher than the surface. If its position is

excessive low, it shall be adjusted by using lift nipple. It must be adjusted while running in 7

casing. The 7casing hanger shall be seated on the top of the lifting nipple. The Christmas tree

shall be installed uprightly and firmly in accordance with relevant regulations.

The well site shall be smooth and neat withou mud, oily dirt and water accumulation. The rat

hole and mouse hole must be backfilled and tamped, and a warning sign shall be set up. If mud,

fresh water and mud materials are needed for testing, the drilling company is responsible to

deliver the field stocks to the test company. In principle, the materials required in the testing

48

program must be managed by the test company after testing. Except for the materials specified

in the agreement between the drilling company and the test company, the other materials out of

the testing program must be managed by the drilling company after testing.

The well completion data documents shall be complete, accurate and tidy, and shall be delivered

before the specified date.

The casing head shall be fully installed with pressure gauge and outgoing pipeline (fixed

firmly). The cementing quality is good with no oil&gas channeling and no pressure in the

annulus.

The following working procedures shall be done during well completion period:

1. Run in all of production casing and then carry out cementing.The cement job must be

qualified. The production casing string was successively seated and hanged on the casing

head with good sealing. Inject sealing compound and perform pressure test. The pressure

test must be qualified. No fluid invasion into the casing or leakage out of the casing.(The

above mentioned jobs will be confirmed by signatures of drillin crew leader and

supervisor).

2. Drift the casing with test drift diameter gauge. It shall be confirmed by signatures of drilling

crew leader and supervisor.

3. Run the drill string to the artificial hole bottom. Displace the hole with fresh water, then

stabilize for 24h, no overflow occurs, circulate and observe possible oil, gas and water

invasion. The pressure test is qualified which confirms the success of the cement job and

good isolation of the casing. Displace the hole with mud which can control all the pay

zones.

4. The well tested with the former rig will be delivered to the test company.

5. The following work will be done for the well tested with another rig:

a. Pull drill string out of hole and fill up mud simultaneously (no overflow).

b. Disassemble BOP stack.

c. Pull the production casing out of the tubing hanger or cut it from 1ft above the top

flange of the casing head (no deformation on the end surface, no junks left in the hole).

d. Clean the top flange of the casing head, tubing hanger thread, dope corrosion inhibiting

oil on the tubing hanger thread, daub grease in the steel ring groove or inject engine oil

fully.

e. Cover strawhat-type protective cap (keep the lower edge at the same level with the top

flange of the casing head), secure the foure corners with four screws.

f. Clean the casing head, cellar. Install all the valves (double valves for each side of

49

casing head), stopcock, pressure gauge. The bleeding lines for various casing heads

shall be installed and fixed firmly.

g. Deliver the well to the test compmay when the rig has been moved from the well site.

Provide complete documents which fully demonstrate the well conditions. Perform

pressure test and cofirm the success of the test with the presence of both parties and

carry out a written transfer procedures.

14 HSE requirements

14.1 Basic requirements

Implement the laws, regulations, standards and systems on safety, environment protection,

professional health, fire fighting, emergency solutions,etc, which are established by the resource

country, cocal government and Sinopec.

Companies engaged in development of oil ang gas resources shall obtain the Safety

Production License and establish the HSE management system which involves sigle well

safety and environment risk analysis. Peform HSE check and drill. Provide sufficient

pollution-control equipment and realize standard pollutant discharge.

Drilling crew shall establish a HSE leadership group with clear working duties. The follwing

ideas shall be followed by the drilling crew: safety first, precaution crucial, all staff

participation, comprehensive management, environment improvement, health protection,

scientific management, sustainable development. Pursue the goal of no accident, no damage to

human health, any environment damage and first-class HSE achievement in China.

Drilling crew shall hold the effective certificates in accordance with the relevant regulations of

the resource country and local government.

The drilling crew shall provide effective inspection reports or certificates and signs for the

following equipment: safety equipment and safety accessories, special equipment, measurement

instruments, H2S detection device, derrick, etc.

Drillin g crew qualification and personnel requirements:

The toolpusher and HSE management personnel shall hold Safety Production Management

Certificate ;

a. All the personnel shall hold HSE operation certificates;

b. Special operating personnel (electrical operation, metal welding, boiler operator, crane

operator, etc.) shall hold Special Operation Certificate;

c. Toolpushers, drilling engineer (technician), security personnel, stud driller, driller, assistant

50

driller, derrickman shall hold effective peration Certificate and Well

Operation Certificate.

d. Cooks shall hold effective health certificates.

e. All the people who work in a place where H2S may exist shall accept H2S traninning and

obtain H2S Protection Technique Traninning Certificate.

Incorporate in a single system the observations made and reported by all the service companies.

Ongoing campaigns and incentives for reporting of unsafe conditions and actions

Establish mechanisms focused on example-based change in mentality.

Effective procedure for analysis, tracking and closing of reports.

Tracking and daily report of RIT cards to operations coordinator to guarantee effective closing.

Stricter control at supervisory levels in respect to observance of PPE usage policies

Strict tracking of reprimands for failure to comply with use of PPE.

14.2 Liquid and solids waste managment program

In accordance with the Environmental management plan a zodme area will be available in the

location to mix and dispose water-based cuttings.

The solids and liquid waste management program is intended to reduce waste generation by

reutilizing resources. This may be accomplished through proper management of the solid

control equipment, where centrifugal decanters play a very important role. Moreover, water

must be managed on the basis of a culture aimed on saving and recycling.

14.3 Waste management objects (HSE)

Full compliance with parameters for disposal of solids and liquids

Reduction of costs on account of