Drilling Plan Anlaysis and Comparison of two directional well of Gandhar Field

7/29/2019 Drilling Plan Anlaysis and Comparison of two directional well of Gandhar Field

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Drilling Plan, Analysis and Comparison

of two directional wells of Gandhar

Field

Report submitted for the requirements of the course Industrial

Internship, VII semester, Academic Session 2012-2013

By

PRAKHAR MATHUR - 09BT01180

SCHOOL OF PETROLEUM TECHNOLOGY

PANDIT DEENDAYAL PETROLEUM UNIVERSITY

GANDHINAGAR, GUJARAT, INDIA


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CONTENTS

Pg. No.

LIST OF FIGURES (i)

ABBREVIATIONS USED (ii)

ACKNOWLEDGEMENTS 1

CHAPTERS:

1. ABOUT ONGC Ltd, ANKLESHWAR ASSET 22. ABSTRACT 53. WELL PLANNING 6

3.1. Activities before start of drilling programme 6

3.2.Input data for well planning 6

3.3.Drilling programme preparation 6

3.4.Geo-Technical order 7

3.5.Details of well GNDDS and GNDEB 8

4. CASING PROGRAMME 94.1.Introduction 9

4.2.Types of casing 9

4.3.Selection of casing seats 10

4.4.Design criteria 11

4.4.1. Collapse Criterion 114.4.2. Burst Criterion 134.4.3. Design and Safety Factor 144.4.4. Tension Criterion 154.5.Casing Plan of well GNDDS 16

4.6.Casing Plan of well GNDEB 27

5. THE DRILL STRING 385.1.Drill stem auxiliaries 39

5.2.Drill string design of well GNDDS 40

5.3.Drill string design of well GNDEB 45


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6. HYDRAULIC PROGRAMME 516.1.Drilling Fluid 51

6.2.Hydraulics design of well GNDDS 52

6.3.Hydraulics design of well GNDEB 67

7. CEMENTING 827.1.Primary Cementing 82

7.2.Squeeze Cementing 83

8. ANALYSIS AND COMPARISON OF GNDDS & GNDEB 849. FIELD VISITS 85

9.1.Visit to GGS-3 85

9.2.Visit to the rig Carwell-10 86

9.3.Visit to the rig F-6100-2 87

9.4.Visit to the rig E-1400-7 88

9.5.Visit to SCADA system 88

REFERENCES 90


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List of Figures Pg. No.

Fig.1: Fields of Akleshwar asset and their location 4

Fig.2: Example of idealised casing seat selection 11

Fig.3: Mud level inside casing after lost circulation 13

Fig.4 Burst design 14

Fig.5 Burst design for production casing 14

Fig.6: Plot between Pressure (ppg) V/S Depth(m), indicating the casing shoes 19

Fig.7: Burst and Collapse Design of Surface Casing V/S depth 22

Fig.8: Burst and Collapse Design of Intermediate Casing V/S depth 24

Fig. 9: Burst and Collapse Design of Production Casing V/S depth 26

Fig.10: Plot between Pressure (ppg) V/S Depth (m), indicating the casing shoes 30

Fig.11: Burst and Collapse Design of Surface Casing V/S depth 33

Fig.12: Burst and Collapse Design of Intermediate Casing V/S depth 35

Fig.13: Burst and Collapse Design of Production Casing V/S depth 37

Fig.14: The drill stem members 38

Fig.15: Neutral point in drill collar 39

Fig. 16: Major Cement Additives 84


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Abbreviations used:

ONGC Oil and Natural Gas Corporation

OMW Original Mud Weight

EMW Equivalent Mud Weight

CTF Central Tank Farm

GGS Group Gathering Station

SPM Strokes per minute

CSD Casing Seat Depth

SCADA Supervisory Control and Data Acquisition

CPF Central Processing Facility

TVD True Vertical Depth

MD Measured Depth

CP Casing Policy

PHPA Partially Hydrolysed Poly Acrylamide

AZI Azimuth

INC Inclination

Formpress Formation Pressure

Gasgrad Gas Gradient

FBHP Formation Bottom Hole Pressure

HWDP Heavy Weight Drill Pipe

Ppf Pounds per foot

BTC Buttress Thread Casing

BHA Bottom Hole Assembly

BF Buoyancy Factor

SF Safety Factor

WOB Weight on Bit

BHHP Bottom Hole Hydraulic Pressure


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ACKNOWLEDGEMENTS

First of all, I would like to thank Training & Placement cell of Pandit Deendayal

Petroleum University for giving me this wonderful opportunity to perform my summer

training in ONGC Ankleshwar.

I wish to thank OIL AND NATURAL GAS CORPORATION LTD., Ankleshwar

Asset for allowing me to complete my training program at their premises and for providing

all the needful facilities for the successful completion of the entire program.

I would like to express my sincere gratitude towards my mentor Mr. S.K. Mandloi

(CE) Drilling Services for his continuous guidance and for enlightening me with vital

knowledge throughout the program. Working under his guidance has been a privilege and a

fruitful learning experience.

I would also like to thank Mr. M.M. Sharma (CE) Drilling Services for his constant

support and for arranging several field visits during the course of my training.

I express my deep gratitude to those who have helped and encouraged me in various

ways in carrying out this Project work. I would like to extend my thanks and would want to

acknowledge the ONGC personnel for sharing their valuable knowledge.

Prakhar Mathur


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1.ABOUT ONGC Ltd. ANKLESHWAR ASSETAnkleshwar is the first Asset where Oil and Natural Gas Corporation discovered oil in

1960. Its also the largest asset located in South of Gujarat in Bharuch district. Ankleshwar

asset is spread along Contiagal, Kosamba, Kim, Jalod, Rajpadi, Gandhar, Dahej, Nada, Kavi,

Dabka, Alamgir oil fields.

The Asset has two main fields: Ankleshwar field and Gandhar field. While

Ankleshwar is a mature field, Gandhar is a relatively new field which was discovered in

1984.

Ankleshwar field

Ankleshwar oil field is the biggest and the oldest oil-field of Oil and Natural Gas

Corporation Ltd. This is oil field is located at a distance of 6 km SSW of Ankleshwar Town

in Gujarat State. This field is situated in Narmada-Tapti Tectonic Block of Cambay Basin and

having an areal extent of 32.47 sq. km.

Geological Survey of India started exploration of oil and gas in the field as early as1930s. Subsequently the geologists of Oil and Natural Directorate of India mapped the area

and carried out Gravity Magnetic Survey during the year 1957-1958. Seismic survey was

carried out in the year 1958-1959. An exploratory test well was released for confirming the

hydrocarbon potential and the well was drilled in the year 1960 to a depth of 1969 m.

Hydrocarbon accumulations have been discovered in arenaceous reservoirs within

Cambay shale, Ankleshwar, Dadhar and Babaguru formations. Major oil pools are found in

multi-layer sandstone reservoirs within Hazad and Ardol members of Ankleshwar formation.

The sandstones of Ankleshwar formation represent series of delta front sands of the pro

Narmada Delta developed in the South Cambay Basin.

Geology and Lithology

Ankleshwar field comprises of mainly three producing horizons i.e. Lower productive

group developed in Cambay shale, middle and upper productive group development in


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Ankleshwar formation.The upper producing formation called Adol member of Ankleshwar

formation is located within the Telwa and Kanwa and Cambay shale.

Observation on Reservoir Properties:-

Major formations are in Ankleshwar formation and Cambay shale.

Initial super hydrostatic pressure has presently reduced to sub hydrostatic.

The sands S-5 and LS-1 have got good porosity and moderate permeability values.

All other sand layers are having good values of porosity and permeability

Wells status of Ankleshwar (as on 01-12-10)

TOTAL WELLS 604

OIL WELLS 218

GAS WELLS 58

INJECTORS 118

OFF INJ 4

EFF. DISP. 4

OBS/FU 113

TO BE ABANDONED 3

ABANDONED 86


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Backup

Ankleshwar Asset fields

Major Fields :Gandhar,Ankleshwar

Medium Fields :Dabka,Dahej,Gajera,Jambusar,Kim,

Kosamba,Kudara,Nada,N.Sarbhan,

Sisodara,S.W.Motwan,W.Motwan,

Olpad

Marginal Fields :Andada,Degam,Katpur,Pakhajan ,

S.Malpur,Elao

Fig.1: Fields of Akleshwar asset and their location


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2.ABSTRACTThe project deals with the process for drilling a well for development purpose. The

entire project reflects on the methodology and the operations required for the drilling, casing

and completion of an oil well which includes Drill String Design, Hydraulic Programme

Design and Casing Design and thus fulfilling the requirement for a safe and optimised oil

well plan.

The project was planned and executed on the basis of data provided by the ONGC

Ltd. This data included the Geological Parameters; like lithological section, expected

formation temperature, expected formation pressure, Mud Parameters; like mud weight,

viscosity, PV/YP, percentage of sand, gelation and Drilling Parameters; like Hole size,

meterage per bit, Weight on Bit, discharge of pump.

After taking all the relevant parameters in mind the well geometry was designed and

an optimised drilling programme was framed to be executed.

On the basis of the insights given by ONGC Ltd. and under the guidance of a learned

guide various parameters of the project were studied and some of the operations were seen in

the field which were being conducted at the time of the visit.


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3.WELL PLANNINGObjective

Well Planning is an orderly process involving a number of steps. The Objective of Well

Planning is to formulate a drilling programme for many variables for drilling a well that has

the following characteristics:

1. Safety

2. Minimum cost

3. Usable

3.1.ACTIVITIES BEFORE START OF DRILLING PROGRAMME Objective :

Costing and Sanctions :

Release of Location :

Release Order No. :

Rig :

Civil Works : access roads made,

waste mud pits dug, water tanks

installed

Accommodation bunkers : installed

Other equipments / machinery :

transported and handed over

3.2.INPUT DATA FOR WELL PLANNING

The information required for planning of a well are:

1. The Objective of the well

2. Well data package consisting of seismic data, location map, structural map, expected

pore pressure, offset and correlation logs and information on formation type, top and

thickness.

3. Offset and correlated drilled well data considering of bit record, mud reports, mud

logging data, drilling reports, well completion reports, complication reports and

production/injection histories.

4. Proposed logging, testing and coring programme.

5. Government reflection and Companys policy.3.3.DRILLING PROGRAMME PREPARATION

The preparation of good Drilling Programme is very vital for safe and effective

drilling operation. Drilling Programme can be broke down into 12 main sections:


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1. Well details

2. Well objective

3. Casing Policy

4. Wellhead selection

5. BOP requirements

6. Cementing programme

7. Deviation programme

8. Survey requirements

9. Mud programme

10.Bit and Hydraulics programme

11.Evaluation requirements

12.Estimation of well cost3.4.GEO-TECHNICAL ORDER

The first step before spudding any well is the well programming. This programming

furnishes guidance for all parties concerned in drilling of the well. An effective well

programming before undertaking the drilling of an exploratory well is a must. This serves as

a guide to the Geologists, Drillers, Chemist and etc. This programming of the well which

covers all geological and other technical data and serves as a guide during a course of the

drilling is termed as GEO-TECHNICAL ORDER and is jointly prepared by the Geologist,

Chemist and Driller.

The GTO furnishes the guide to everyone connected with the drilling of the well. It

thus provides a guide line and work plan and can be modified if and when required, by the

concerned persons of the programme, as per the actual well conditions and necessities.

Salient Features of the Geo-Technical Order

a) General Data

Location

o Longitude

o Latitude

State

Area

Projected Depth

Date of Spudding

Well Number

Tentative sea bed / water

depth

b) Geological Data

Depth

Age

Formation

Lithology

Interval of coring

Electro logging

Angle of Dip

Oil / Gas show

Formation Pressure

c) Mud parameters


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Specific Data

Viscosity

Static Flow Stress

Percentage of sand

pH

d) Drilling Data (Technical Data) Casing policy and rise of

cement

Type of drilling

Type of size of bit

Number of bit expected

Meterage per bit

Weight on bit RPM of rotary

Discharge of pump

Stand Pipe Pressure

Pump discharge

Bit nozzle details

Liner size

SPM

Rearing of casing line

Drilling Time

Remarks, If any

3.5. Details of well GNDDS and GNDEBDetails GNDDS GNDEB

State Gujarat Gujarat

District Bharuch Bharuch

Area Gandhar Gandhar

Well Type Development Development

Projected Depth 3060m (TVD), 3177m (MD) 3065.4m (TVD), 3092m (MD)

Well Profile L Profile S Profile

Type of Drilling Rotary + Motor Rotary + Motor

Type of Rig E-760-17 F-6100-II

Power to Draw works 2 DC motors 2000 HP

Slush Pumps A-850-PT A-1100-PT

Well head set up 3CP X 5m -7 Completion 3CP X 5m -7 Completion

Casing Size 13 3/8 X 9 5/8 X 7 13 3/8 X 9 5/8 X 7

Lattitude & Longitude 21 55 47.89 & 7241 13.10 21 53 09.96 & 7237 55.64

Estimated Cost Rs. 13,56,25,193/- Rs. 17,12,56,153/-


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4.CASING PROGRAMME4.1. INTRODUCTION

The functions of Casing may be summarised as follows:

a) To keep the hole open and to provide support for weak, vulnerable or fractured

formations. In the latter case, if the hole is left uncased, the formation may cave in

and re drilling of the hole will then become necessary.

b) To isolate porous media with different fluid/pressure regimes from contaminating the

pay zone. This is basically through the combined presence of cement and casing.

Therefore, production from a specific zone can be achieved.

c) To prevent contamination of near-surface fresh water zones.

d) To provide a passage for hydrocarbon fluids, most production operations are carried

out through special tubings which are run inside the casing.

e) To provide a suitable connection for the wellhead equipment and later the Christmas

tree. The casing also serves to connect the Blowout Prevention Equipment (BOPs)

which is used to control the well while drilling.

f) To provide a hole with a known diameter and depth to facilitate the running of testing

and completion equipment.

4.2.TYPES OF CASING

Conductor Casing

Surface Casing

Intermediate Casing

Production Casing

Liner


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4.3.SELECTION OF CASING SEATS

The following parameters must be carefully considered in the selection:

a) Total depth of well

b) Pore pressures

c) Fracture gradients

d) The probability of shallow gas pockets

e) Problem zones

f) Depth of potential prospects

g) Time limits on open hole drilling

h) Casing program compatibility with existing wellhead systems

i) Casing program compatibility with planned completion programme on production

wells.

j) Casing availabilitysize, grade and weight

k) Economics

Example of Casing seat selection:

a) Casing is set at depth 1, where pore pressure is P1 and fracture pressure if F1.

b) Drilling continues to depth 2, where pore pressure P2 has risen to almost equal the

fracture pressure F1 at the first casing seat.

c) Another casing string is therefore set at his depth, with fracture pressure F2.

d) Drilling can thus continue to depth 3, where pore pressure P3 is almost equal to

fracture pressure F2 at the previous casing seat.


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Fig.2: Example of idealised casing seat selection

4.4.DESIGN CRITERIA

There are three basic forces which the casing is subjected to: collapse, burst and tension.

These are the actual forces that exist in the wellbore. They must be calculated and must be

maintained below the casing strength properties. In other words, the collapse pressure must

be less than the collapse strength of the casing and so on.

For directional wells a correct well profile is required to determine the true vertical depth

(TVD). All wellbore pressures and tensile forces should be calculated using true vertical

depth only. The casing lengths are first calculated as if the well is a vertical well and then

these lengths are corrected for the appropriate hole angle.

4.4.1. COLLAPSE CRITERIONCollapse pressure originates from the column of mud used to drill the hole, and acts on the

outside of the casing. Since the hydrostatic pressure of a column of mud increases with depth,

collapse pressure is highest at the bottom and zero at the top.

This is a simplified assumption and does not consider the effects of internal pressure.

For practical purposes, collapse pressure should be calculated as follows:

Collapse pressure = External pressureInternal pressure


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The actual calculations involved in evaluating collapse and burst pressures are usually

straight forward. However, knowing which factors to use for calculating external and internal

pressures is not easy and requires knowledge of current and future operations in the wellbore.

Until recently, the following simplified procedure was used for collapse design:

a) Casing is assumed empty due to lost circulation at casing setting depth (CSD) or at

TD of next hole.

b) Internal pressure inside casing is zero.

c) External pressure is caused by mud in which casing was run in.

d) No cement outside casing.

Therefore

Collapse pressure (C) = mud density x depth x acceleration due to gravity

C = 0.052 x mx CSD.psi

Where m is in ppg and CSD is in ft

LOST CIRCULATION

If collapse calculations are based on 100% evacuation then the internal pressure (or back-

upload) is to zero. The 100% evacuation condition can only occur when:

a) The casing is run empty

b) There is complete loss of fluid into a thief zone (say into a cavernous formation)

c) There is complete loss of fluid due to gas blowout which subsequently subsides

None of these conditions should be allowed to occur in practice with the exception of

encountering cavernous formations.


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Fig.3: Mud level inside casing after lost circulation

4.4.2. BURST CRITERIONIn oil well casings, burst occurs when the effective internal pressure inside the casing(internal

pressure minus external pressure) exceeds the casing burst strength.

In development wells, where pressures are well known the task is straight forward. In

exploration wells, there are many problems when one attempts to estimate the actual

formation pressure including:

The exact depth of the zone (formation pressure increases with depth)

Type of fluid (oil or gas)

Porosity, permeability

Temperature

BURST CALCULATIONS

Burst Pressure, B is given by


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B = Internal PressureExternal Pressure

Fig.4 Burst design

Internal Pressure : Burst Pressures occur when formation fluids enter the casing while drilling

or producing next hole. The maximum formation pressure will be encountered when reaching

the TD of the next hole section.

Fig.5 Burst design for production casing

4.4.3. DESIGN & SAFETY FACTORSCasings are never designed to their yield strength or tensile strength limits. Instead, a factor is

used to derate the casing strength to ensure that the casing is never loaded to failure. The

differences between design and safety factors are given below.

4.4.3.1.SAFETY FACTOR

Safety factor uses a rating based on catastrophic failure of the casing.


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Safety Factor =

4.4.3.2.DESIGN FACTOR

Design Factor =

A Design Factor is usually equal to or greater than 1.The design factor should always allow

for forces which are difficult to calculate such as shock loads.

The burst design factor (DFB) is given by:

DFB =

Similarly, the collapse design factor is given by:

DFC =

4.4.4. TENSION CRITERION:

Most axial tension arises from the weight of the casing itself. Other tension loadings can arisedue to: bending, drag, shock loading and during pressure testing of casing.

In casing design, the uppermost joint of the string is considered the weakest in tension, as it

has to carry the total weight of the casing string. Selection is based on a design factor of 1.6

to 1.8 for the top joint.

Due to complexity and lack of available data, this criterion has not been included in casing

design performed below.


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4.5. Casing Plan of well GNDDSThe following data was noted from the DPR (Daily Progress Report) during drilling:

DEPTH(m)

MUD

WEIGHT(g/cc)

VISCOSIT

Y(cp) DATE SPCL OPPN LITHOLOGY

15 1.05 45 13-May - ALLUVIUM

25 1.05 45 14-May - ALLUVIUM

60 1.05 45 15-May - ALLUVIUM

205 1.05 55 16-May

CASING

LOWRING SAND

205 1.05 55 17-May CEMENTING SAND

205 1.05 55 18-May - SAND

500 1.08 47 19-May -

CLAY STONE

+SHALE

710 1.1 45 20-May - SAND

980 1.12 48 21-May - CLAY STONE

1125 1.13 47 22-May - CLAY

1330 1.14 48 23-May -

CLAY STONE

+SHALE

1356 1.14 48 24-May -

CLAY STONE

+SHALE

1516 1.17 48 25-May -

SAND + SILT

+SHALE

1516 1.17 48 26-May

CASING

LOWERING

SAND + SILT

+SHALE

1516 1.17 48 27-May

CASING

LOWRING

SAND + SILT

+SHALE

1602 1.18 47 28-May CEMENTING CLAY

1602 1.18 47 29-May

MUD CHANGE-

KCl PHPA MUD CLAY

1610 1.18 48 30-May

MUD CHANGED

TO POLYMER

MUD CLAY

1632 1.18 50 1-Jun

MUD MOTER

CHANGE CLAY


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1724 1.19 58 2-Jun AZI-266,INC-7.6 CLAY + SAND

2030 1.19 58 4-Jun AZI-241.4,INC-23 SAND STONE

2063 1.19 58 5-Jun

AZI-241.5,INC-

23.18 SAND STONE

2120 1.19 58 6-Jun

FINISH DIR,2063-

2120 POOR ROP SAND STONE

2120 1.19 58 7-Jun

TRIPPING,CHANG

E MUD MOTER SAND STONE

2218 1.23 60 8-Jun AZI-240.5,INC-24.6

SAND+SILT+SHAL

E

2425 1.22 58 10-Jun - SHALE

2503 1.25 58 13-Jun - SHALE

2555 1.25 62 14-Jun - SHALE

2564 1.25 62 19-Jun 9 M KICK

SAND+SILT+SHAL

E

2564 1.25 60 20-Jun STUCKUP

SAND+SILT+SHAL

E

2605 1.28 64 22-Jun

STUCKUP

REMOVED

SAND+SILT+SHAL

E

2795 1.28 61 25-Jun -

SAND+SILT+SHAL

E

2838 1.28 61 26-Jun STUCKUP

SAND+SILT+SHAL

E

2838 1.28 61 1-Jul

STUCKUP

CONTINUED

SAND+SILT+SHAL

E

Estimated pore pressure data is obtained by subtracting safety factor from the mud weights.

Fracture gradient data is provided by the company.

PORE PRESSURE

(g/cc)

MUD WEIGHT

(lb/gal)

PORE PRESSURE

(lb/gal)

FRACTURE GRADIENT

(lb/gal)

1.01 8.76225 8.42845

1.01 8.76225 8.42845

1.01 8.76225 8.42845

1.01 8.76225 8.42845


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1.01 8.76225 8.42845

1.01 8.76225 8.42845

1.04 9.0126 8.6788 9.85

1.06 9.1795 8.8457 9.955

1.08 9.3464 9.0126 10.09

1.09 9.42985 9.09605 10.1625

1.1 9.5133 9.1795 10.265

1.1 9.5133 9.1795 10.278

1.13 9.76365 9.42985 10.358

1.13 9.76365 9.42985 10.358

1.13 9.76365 9.42985 10.358

1.14 9.8471 9.5133 10.4011.14 9.8471 9.5133 10.401

1.14 9.8471 9.5133 10.405

1.14 9.8471 9.5133 10.416

1.15 9.93055 9.59675 10.462

1.15 9.93055 9.59675 10.615

1.15 9.93055 9.59675 10.6315

1.15 9.93055 9.59675 10.66

1.15 9.93055 9.59675 10.66

1.19 10.26435 9.93055 10.709

1.18 10.1809 9.8471 10.8125

1.21 10.43125 10.09745 10.8515

1.21 10.43125 10.09745 10.8775

1.21 10.43125 10.09745 10.882

1.21 10.43125 10.09745 10.882

1.24 10.09745 10.9025

1.24 10.09745 10.9975

1.24 10.09745 11.019

1.24 10.09745 11.019


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Fig.6 Plot between Pressure (ppg) V/S Depth(m), indicating the casing shoes


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4.5.1. Differential Sticking Calculation:Mud Weight at 1640 m =10.425 ppg

Diff. Stick Potential = (10.425-8.428)*0.052*5380.5774=558.7406psi (


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4.5.3. SURFACE CASING:Depth = 200m = 656.1679ft

Burst Criteria:

Load

De

pth

Back

up

Resul

tant

Design

(R*1.1)

Injection

Pressure

(fracture press +

1)*depth*0.052

(9.8 +

1)*656.1679*0

.052

368.5

039 200

287.5

695

80.93

437 89.02781

Surface

Pressure

IP -

gasgrad*depth*0.05

2

(10.8-

1.923)*656.16

79*0.052

302.8

897 0 0

302.8

897 333.1787

A graph has been plotted from above table.

Collapse Criteria:

Load

Dept

h

Backu

p

Resulta

nt Design

cement length 656.168 ft

491.167

2 200 0

491.167

9

540.284

7

mud length 0 0 0 0 0 0



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Fig.7: Burst and Collapse Design of Surface Casing V/S depth

By referring to charts, we conclude that recommended Grade: K55, 61ppf, BTC

0

50

100

150

200

250

0 100 200 300 400 500 600

Depth(m)

Pressure (psi))

Burst Design

Collapse Design

0

50

100

150

200

250

0 200 400 600

Collapse Load

Resultant

Design

0

50

100

150

200

250

0 100 200 300 400

Burst Load

Backup

Resultant

Design


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4.5.4. INTERMEDIATE CASING :Depth =1600m =5249.28 ft

X = 11.827 , Y= 5237.452

Burst Criteria:


Collapse Criteria :


Load

Dept

h

Back

up

Result

ant

Design

(R*1.1)

Injection

Pressure

(fracture press +

1)*depth*0.052

3111.

773

3111.

773 1600

2300.

528

811.24

47 892.3692

2593.

262

3.60

487

5.183

254

2588.0

79 2846.887

Surface

Pressure

IP -

gasgrad*depth*0.052

2586.

845

2586.

866 0 0

2586.8

66 2845.553

0.052*formpress L = 1296.3 m=4253ft

*CSD=mudgrad*"L"*0.052 Load Depth Backup

Resulta

nt Design

cement length 1312.336

2998.87

1 1600

2300.02

2 698.849

768.733

9

mud length 3937.008

2016.53

5 1200

1590.30

9 426.2265

468.849

2

996.3419

510.326

3

303.68

5 0 510.3263

561.358

9

0 0 0 0 0


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Fig.8 : Burst and Collapse Design of Intermediate Casing V/S depth

By referring to charts, we conclude that recommended Grade : L80, 43.5ppf BTC

0

200

400

600

800

1000

1200

1400

1600

1800

0 1000 2000 3000 4000

Burst Load

Backup

Resultant

Design

0

200

400

600

800

1000

1200

1400

1600

1800

0 2000 4000

Collapse

Load

Backup

Resultant

Design

0

200

400

600

800

1000

1200

1400

1600

1800

0 500 1000 1500 2000 2500 3000

Depth(m)

Pressure (Psi)

Burst Design

Collapse Design


30/95

25 | P a g e

4.5.5. PRODUCTION CASING :Packer fluid density = 9 lb/gal

FBHP = 2000psi

Burst Criteria:


Collapse Criteria:


Load

Dept

h Backup

Resultan

t

Design

(R*1.0)

10423.228

35

6878.07086

6 3177

4568.04236

2 2310.029 2310.029

FBHP 0 2000 0 0 2000 2000

Collapse Load Depth Backup Resultant Design (R*1)

Cementing 1564.96063 5961.986811 3177 0 5961.987 5961.987

8858.267717 4790.551181 2700 0 4790.551 4790.551

Mud 0 0 0 0 0 0


31/95

26 | P a g e

Fig.9 : Burst and Collapse Design of Production Casing V/S depth

By referring to charts, we conclude that recommended Grade : L80, 29ppf, BTC

0

500

1000

1500

2000

2500

3000

3500

0 5000 10000

Burst Load

Backup

Resultant

Design

0

500

1000

1500

2000

2500

3000

3500

0 5000 10000

Collapse

Load

Backup

Resultant

Design

0

500

1000

1500

2000

2500

3000

3500

0 1000 2000 3000 4000 5000 6000 7000

Depth(m)

Pressure (Psi)

Burst Design

Collapse Design


32/95

27 | P a g e

4.6. Casing Plan of well GNDEBThe following data was noted from the DPR (Daily Progress Report) during drilling:

DEPT

H (m)

MUD

WEIGHT

(g/cc)

VISCOSI

TY DATE SPCL OPPN LITHOLOGY

15 1.06 42 9-May - ALLUVIUM

63 1.05 5010-May - ALLUVIUM

170 1.05 5011-May - GRAVEL

205 1.05 4512-May Casing Lowering

CLAYSTONE +SAND

205 1.05 4513-May Reaming

CLAYSTONE +SAND

205 1.05 45

14-

May

Casing Lowering Shoe at

203m

CLAYSTONE +

SAND

205 1.05 4515-May -

CLAYSTONE +SAND

275 1.05 4716-May -

CLAYSTONE +SAND

525 1.1 4417-May -

CLAYSTONE +SAND

648 1.1 4518-May

Circulation upto 648m , BHAchanged

CLAYSTONE +SAND

665 1.11 4819-May -

CLAYSTONE +SAND

737 1.11 46

20-

May -

CLAYSTONE +

SAND

930 1.13 4721-May Drilling Sliding CLAY

1030 1.13 5022-May Sliding Angle 90.3 Azi 325.4 SAND + SILT

1150 1.14 53

23-

May - CLAY

1155 1.14 5324-May

Sliding Drilling from 1150-1155 CLAY

1321 1.14 48

25-

May

Sliding Drilling from 1155-

1321

CLAY +SHALE +

SAND

1463 1.15 4826-May

Sliding Drilling from 1321-1463 Azi 330.9 Angle 5.2 CLAY

1575 1.15 5527-May - SAND + SILT

1614 1.15 6528-May Dir Drilling : 1580-1614 SAND + SILT

1614 1.15 5529-May - SAND + SILT

1707 1.2 4830-May -

CLAYSTONE +SILT

1809 1.2 48 1-Jun Casing Lowering

SAND + SILT +

SHALE


33/95

28 | P a g e

1809 1.2 48 2-Jun Casing LoweringSAND + SILT +SHALE

1809 1.2 62 4-Jun BIT CHANGED to 8 1/2in.SAND + SILT +SHALE

1809 1.2 62 5-Jun Casing Completed

SAND + SILT +

SHALE

1809 1.2 62 6-Jun -

SAND + SILT +

SHALE

2102 1.23 62 7-Jun -SAND + SILT +SHALE

2208 1.24 64 8-Jun - SAND + SILT

2316 1.24 64 10-Jun PDC bit ADDEDSAND + SILT +SHALE



3100 1.26 60 17-Jun - SHALE

3112 1.26 60 19-Jun LOGGING SHALE

3112 1.26 60 20-Jun - SHALE

3112 1.26 60 22-Jun - SHALE

3112 1.26 65 23-Jun - SHALE

3112 1.26 65 25-Jun - SHALE

3112 1.26 65 26-Jun - SHALE

3112 1.26 65 1-Jul LOGGING SHALE

Estimated pore pressure data is obtained by subtracting safety factor from the mud weights.

Fracture gradient data is provided by the company.


34/95

29 | P a g e

PORE PRESSURE

(g/cc)

MUD WEIGHT

(lb/gal)

PORE

PRESSURE

(lb/gal)

FRACTURE

GRADIENT

(lb/gal)

1.02 8.8457 8.5119

1.01 8.76225 8.42845

1.01 8.76225 8.428451.01 8.76225 8.42845

1.01 8.76225 8.42845

1.01 8.76225 8.42845

1.01 8.76225 8.42845

1.01 8.76225 8.42845

1.06 9.1795 8.8457 9.85

1.06 9.1795 8.8457 9.955

1.07 9.26295 8.92915 10.09

1.07 9.26295 8.92915 10.1625

1.09 9.42985 9.09605 10.265

1.09 9.42985 9.09605 10.278

1.1 9.5133 9.1795 10.358

1.1 9.5133 9.1795 10.358

1.1 9.5133 9.1795 10.358

1.11 9.59675 9.26295 10.401

1.11 9.59675 9.26295 10.401

1.11 9.59675 9.26295 10.405

1.11 9.59675 9.26295 10.416

1.16 10.014 9.6802 10.462

1.16 10.014 9.6802 10.615

1.16 10.014 9.6802 10.6315

1.16 10.014 9.6802 10.66

1.16 10.014 9.6802 10.66

1.16 10.014 9.6802 10.709

1.19 10.26435 9.93055 10.8125

1.2 10.3478 10.014 10.8515

1.2 10.3478 10.014 10.8775

1.22 10.5147 10.1809 10.882

1.22 10.5147 10.1809 10.8821.22 10.5147 10.1809 10.9025

1.22 10.5147 10.1809 10.9975

1.22 10.5147 10.1809 11.019

1.22 10.5147 10.1809 11.019

1.22 10.5147 10.1809

1.22 10.5147 10.1809

1.22 10.5147 10.1809

1.22 10.5147 10.1809


35/95

30 | P a g e

Fig.10: Plot between Pressure (ppg) V/S Depth(m), indicating the casing shoes


36/95

31 | P a g e

4.6.1. Differential Sticking Calculation:Mud Weight at 1820 m =10.525

Diff Stick Potential=(10.02-8.428)*0.052*5971.1286=494.31391(


37/95

32 | P a g e

4.6.3. SURFACE CASING:Depth = 200m= 656.1679ft

Burst Criteria:

Load

Dept

h

Back

up

Result

ant

Design

(R*1.1)

Injection Pressure

(fracture press +

1)*depth*0.052

368.50

39 200

287.

5695

80.934

37 89.02781

Surface Pressure

IP -

gasgrad*depth*0.052

302.88

97 0 0

302.88

97 333.1787


Collapse Criteria:

Load Backup Resultant Design

cement length 200 491.1679 0 491.1679 540.2847

mud length 0 0 0 0 0



38/95

33 | P a g e

Fig.11 : Burst and Collapse Design of Surface Casing V/S depth

By referring to charts, we conclude that recommended Grade : K55, 61ppf, BTC

0

50

100

150

200

250

0 100 200 300 400

Burst Load

Backup

Load

Resultant

Design

0

50

100

150

200

250

0 200 400 600

Collapse

Load

Resultant

Design

0

50

100

150

200

250

0 100 200 300 400 500 600

Depth(m)

Pressure (Psi)

Burst Design

Collapse Design


39/95

34 | P a g e

4.6.4. INTERMEDIATE CASING:X= 12.19 ft, Y=5893.4 ft

Depth = 1800 m =5905.44 ft

Burst Criteria:

Load

Dept

h

Back

up

Result

ant

Design

(R*1.1)

Injection

Pressure

(fracture press +

1)*depth*0.052

3531.

453

3531.

453 1800

2588.

095

943.3

585 1037.694

2947.

569

3.717

646

5.345

408

2942.

223 3236.446

Surface

Pressure IP - gasgrad*depth*0.052

2940.

909 0 0

2940.

909 3235


Collapse Criteria:

0.052*formpress*CSD=mudgrad*"L"*0.052

L = 1444.78 m= 4740.099 ft

Load Depth Backup Resultant Design

cement length 1312.336 3418.556 1800 2563.446 855.1109 940.622

mud length 4593.176 2436.22 1400 1590.309 845.9115 930.5027

1165.341 618.0969 355.1959 0 618.0969 679.9066

0 0 0 0 0



40/95

35 | P a g e

Fig.12 : Burst and Collapse Design of Intermediate Casing V/S depth

By referring to charts, we conclude that recommended Grade : L80, 43.5ppf, BTC

0

200

400

600

800

1000

1200

1400

1600

1800

2000

0 1000 2000 3000 4000

Burst Load

Backup

Resultant

Design

0

200

400

600

800

1000

1200

1400

1600

1800

2000

0 1000 2000 3000 4000

Collapse

Load

Backup

Resultant

Design

0

200

400

600

800

1000

1200

1400

1600

1800

2000

0 500 1000 1500 2000 2500 3000 3500

Depth(m)

Pressure (Psi)

Burst Design

Collapse Design


41/95

36 | P a g e

4.6.5. PRODUCTION CASING:Packer fluid density = 9 lb/gal

FBHP = 2000psi

Depth =3092m=10144.36ft

Burst Criteria:

Load Depth Backup Resultant Design (R*1.0)

10144.36 6747.559 3092 4445.825 2301.734 2301.734

FBHP 0 2000 0 0 2000 2000


Collapse Criteria:

Load Depth Backup Resultant Design (R*1)

Cementing 1614.173 5865.754 3092 0 5865.754 5865.754

8530.184 4657.48 2600 0 4657.48 4657.48

Mud 0 0 0 0 0 0



42/95

37 | P a g e

Fig.13 : Burst and Collapse Design of Production Casing V/S depth

By referring to charts, we conclude that recommended Grade : L80, 9ppf,BTC

0

500

1000

1500

2000

2500

3000

3500

0 5000 10000

Collapse

Load

Backup

Resultant

Design

0

500

1000

1500

2000

2500

3000

3500

0 1000 2000 3000 4000 5000 6000 7000

Depth(m)

Pressure (Psi)

Burst Design

Collapse Design

0

500

1000

1500

2000

2500

3000

3500

0 5000 10000

Busrt Load

Backup

Resultant

Design


43/95

38 | P a g e

5.THE DRILL STRINGThe drill string is an important part of the rotarydrilling process. It represents one of the

largestinvestments on the rig and its failure results inconsiderable loss of time and money.

The drill stem primarily constitutes members usedfor drilling by the rotary method from

swivel to thedrill bit. It consists of Kelly, drill pipe and bottom holeassembly. The drill pipe

section includesconventional drill pipe and heavy weight drill pipe.

The bottom hole assembly (BHA) may contain:

Drill collars

Stabilizers

Jars

Shock sub

Bit-sub

The drill stem serves for fluid passage from theswivel to the bit, imparts rotary motion to the

bit, allows weight to be set on the bit and lowers/raisesthe bit in the well. In addition, it

provides stability tominimize vibration and bit bouncing, testingformation through drill stemoperations and also permits through pipe evaluation for logs.

Fig.14: The drill stem members


44/95

39 | P a g e

Fig.15: Neutral point in drill collar

The neutral point is usually set to be slightly below the transition between the drill pipe and

the drill collars say two or three drill collars below. For this in design of drill stem, a safety

factor of 0.8 is used to restrict the neutral point within the drill collar assembly. The string

above the neutral point is in tension, and the string below the neutral point is in compression.

It helps to minimize directional control problems by providing stiffness to the BHA.

It minimizes bit stability problems from vibrations, wobbling, bouncing etc.

Spiral drill collars are used to prevent pressure differential sticking in the hole. They

provide a passage for the drilling fluid to relieve the pressure differential.

5.1.DRILL STEM AUXILIARIES

Various auxiliary tools are used with the drill stem, including drill stem subs, vibration

dampeners, lifting subs, stabilisers, reamers, and pipe wipers and protectors. All should

receive proper care andregular inspection.

Drill Stem Subs

Kelly Saver Sub

Vibration Dampeners

Stabilizers and Reamers


45/95

40 | P a g e

5.2. Drill string design of well GNDDSSection 1

Depth 205m

Hole size 17 in

Mud weight 1.05 gm/cc 8.76ppg

Buoyancy factor = 1-(MW/65.5)

= 1-(8.76/65.5)

= 0.866

Safety factor = 0.8

WOB =10 tons

Weght of drill collar in air = WOB/ ( S.FB.FCOS )

=10/ (0.80.866COS 0)

=11 tons

Available drill collar are :-

Size Length of one stand Weight of on stand

8 3 56 m 6 tons

16 2 13/16 56m 7.64 tons

Adjusting the sizes of the drill collars to their effective WOB

Size Weight of one stand No . of stand used Total weight of stands

8 3 6 tons 1 6 tons

16 2 13/16 7.64 tons 1 7.64 tons

Total weight of drillcollar

13 tons

No of HWDP used =1 of 5 size of length 56 m


46/95

41 | P a g e

Nominal weight of HWDP = 71.41 Kg/m

Weight of one HWDP =71.41 56

= 4 tons

Total weight of drill collar and HWDP is

= 13 + 4 tons

= 17 tons

Length of drill pipe can be measured from the following

0.9 ( Yt) = (Wt. of DP + Wt. of DC + Wt. of HWDP) BF SF

Where,

PA = Theoretical Yield Strength.

Yt= Drill Pipe Yield Strength.

BF = Buoyancy Factor.

SF = Safety Factor.

Ldp =

Ldp = 141.78 0.910^3/ ( 0.8 0.866 29.02) (17/ 29.02)

= 5490 m (feasible)

Section 2

Depth 1640m

Hole size 12 in



=1-(10.02/65.5)

=0.847

Safety factor =0.8


47/95

42 | P a g e

WOB = 15 tons


= 15/ (0.80.866COS 7.6)

= 22.33 tons

Available drill collar are:-


8 3 28m 6.1 tons

16 2 13/16 112m 15.28tons



8 3 6 .1tons 2 12.2tons

16 2 13/16 15.28 tons 1 15.28 tons


27 tons



Weight of 10 HWDP = 71.41 56 10

= 40 tons

Total weight of drill collar and HWDP is

= 13 + 4 tons

= 80 tons



Where,


48/95

43 | P a g e




SF = Safety Factor.

Ldp =

Ldp = 141.78 0.910^3/ ( 0.8 0.847 29.02) (80 10^3/ 29.02)

= 3742 m (feasible)

Section 3

Depth = 3177

Hole size = 12 in

Mud weight = 1.3gm/cc 10.855ppg


=1-(8.76/65.5)

=0.83

Safety factor =0.8

WOB = 25 tons


= 25/ (0.80.83COS23 )

= 51 tons



8 3 56 m 6 tons

16 2 13/16 168m 22.8tons



49/95

44 | P a g e


8 3 6 .1tons 3 18.3tons

16 2 13/16 22.8 2 45.6 tons


61 tons

No of HWDP used :- 10 of 5 size of length 56 m

Nominal weight of HWDP :- 71.41 Kg/m

Weight of 10 HWDP :- 71.41 56 10

40 tons

Total weght of drill collar and HWDP is

= 61 + 40 tons

= 101 tons



Where,




SF = Safety Factor.

Ldp =

Ldp = 141.78 0.910^3/ ( 0.8 0.83 29.02) (101 10^3 / 29.02)

= 3140 m (feasible)

Margin of overpull (MOP)

Wt .whole assembly in the hole ( P) = B.F (wt. of drill pipe + wt. of HWDP +wt. of drill collar)


50/95

45 | P a g e

= 0.83 ( 3140 29.02 / 10^3+ 101 10^3)

= 83.9 tons

MOP = Pa-P

= 141.78-83.9

= 57.9 tons

5.3. Drill string design of well GNDEBSection 1

Depth 205m

Hole size 17 in



= 1-(8.76/65.5)

= 0.866

Safety factor = 0.8

WOB =10 tons


=10/ (0.80.866COS 0)

=11 tons



8 3 56 m 6 tons

16 2 13/16 56m 7.64 tons



51/95

46 | P a g e


8 3 6 tons 1 6 tons

16 2 13/16 7.64 tons 1 7.64 tons


13 tons



Weight of one HWDP =71.41 56 = 4 tons


= 13 + 4 tons

= 17 tons



Where,




SF = Safety Factor.

Ldp =

Ldp = 141.78 0.910^3/ ( 0.8 0.866 29.02) (17/ 29.02)

= 5490 m (feasible)

Section 2

Depth 1810m

Hole size 12 in



52/95

47 | P a g e


=1-(10.02/65.5)

=0.847

Safety factor =0.8

WOB = 15 tons

Weight of drill collar in air = WOB/ ( S.FB.FCOS )

= 15/ (0.80.866COS 7.6)

22.25 tons



8 3 28m 6.1 tons

16 2 13/16 112m 15.28tons



8 3 6 .1tons 2 12.2tons

16 2 13/16 15.28 tons 1 15.28 tons


27 tons



Weight of 10 HWDP = 71.41 56 10

= 40 tons


= 13 + 4 tons


53/95

48 | P a g e

= 80 tons



Where,




SF = Safety Factor.

Ldp =

Ldp = 141.78 0.910^3/ ( 0.8 0.847 29.02) (80 10^3/ 29.02)

= 3742 m (feasible)

Section 3

Depth 3112m

Hole size = 12 in

Mud weight = 1.3gm/cc 10.855ppg


=1-(8.76/65.5)

=0.83

Safety factor =0.8

WOB = 25 tons

Weight of drill collar in air = WOB/ ( S.FB.FCOS )


54/95

49 | P a g e

= 25/ (0.80.83COS23 )

= 51 tons



8 3 56 m 6 tons

16 2 13/16 168m 22.8tons


Size Weight of one strand No . of stand used Total weight of stands

8 3 6.1tons 3 18.3tons

16 2 13/16 22.8 2 45.6 tons


61 tons

No of HWDP used :- 10 of 5 size of length 56 m

Nominal weight of HWDP :- 71.41 Kg/m

Weight of 10 HWDP :- 71.41 56 10

40 tons


= 61 + 40 tons

= 101 tons



Where,




55/95

50 | P a g e


SF = Safety Factor.

Ldp =

Ldp = 141.78 0.910^3/ ( 0.8 0.83 29.02) (101 10^3 / 29.02)

= 3140 m (feasible)

Margin of overpull (MOP)

Wt .whole assembly in the hole ( P) = B.F (wt. of drill pipe + wt. of HWDP +wt. of drill collar)

= 0.83 ( 3140 29.02 / 10^3+ 101 10^3)

= 83.9 tons

MOP = Pa-P

= 141.78-83.9 =57.9 tons


56/95

51 | P a g e

6.HYDRAULIC PROGRAMME6.1.DRILLING FLUID

Drilling Fluid or Drilling Mud is a critical component in the rotary drilling process. Its

primary functions are to remove the drilled cuttings from the borehole while drilling and to

prevent fluids from flowing from the formations being drilled, into the borehole. Since it is

such an integral part of the drilling process, many of the problems encountered during the

drilling of a well can be directly, or indirectly, attributed to the drilling fluids and therefore

these fluids must be carefully selected and/or designed to fulfil their role in the drilling

process.

Functions and Properties of a Drilling Fluid

The primary functions of a drilling fluid are:

a) Remove cuttings from the bottom of the hole and carry them to the surface

b) Prevent formation fluids from flowing into the wellbore

c) Maintain wellbore stability

d) Cool and lubricate the drill string and bit

e) transmit hydraulic horsepower to bit

f) Minimise settling of cuttings and weight material in suspension when the circulation

is temporarily stopped. The mud however, should have properties which allow the

cuttings to settle in the surface system.

The drilling fluid must be selected and/or designed so that the physical and chemical

properties of the fluid allow these functions to be fulfilled. However, when selecting the

fluid, consideration must also be given to:

a) The environmental impact of using the fluid

b) The cost of the fluid

c) The impact of the fluid on production from the pay zone.


57/95

52 | P a g e

6.2. Hydraulics design of well GNDDSSECTION: 1

Hole Size = 17

inches

Mud weight = 1.05

Depth interval = 0 m to 205 m

Drill Collar = 8 3 = 56m

6

2

= 56 m

Drill Pipe = 5 Gd E 19.5 ppf XH = 56 m

Pump available = A-850-PT, 2 Nos.

Step: 1

Select Circulation rate for particular annular size and hole size from table D-1

Hole size = 17

inches

Circulation rate = 3000 LPM

Annular velocity = 100 ft/min

= 30 m/min

= 0.5 m/sec

Step: 2

Table D-3 contains the pressure ratings (kg/cm ) and volumetric discharge (in litres per stroke) for

various models of pumps using different liner sizes. Discharge is based on 100% volumetric

efficiency of the pumps

Liner size = 7

No. of pumps = 2

Operating Pressure Limit = 100 kg/cm2

Step: 3

With the pump output found in Table D-3 and the circulation rate (l/min) selected, calculate SPM

SPM = 85 2


58/95

53 | P a g e

Step: 4

Select surface equipment

Surface equipment - Type 3

Step: 5

See Pressure Losses through surface equipment from Table D-5

For surface equipment Type -3


Pressure Losses through surface

equipment

= 6.94 kg/cm2

Step - 6

Determine Pressure loss through drill pipe bore from Table D-6

Pressure loss for entire drill

pipe string

=

Length of drill pipe

Pressure loss through dill pipe

bore

= 27.8 kg/cm2/1000 m

Pressure loss thorough entire

drill pipe string

=

56 kg/cm2

= 1.5568 kg/cm2

Step: 7

Determine pressure loss in drill pipe annulus

For 17

inches hole size and 5 drill pipe

Pr. Loss through drill pipe

annulus

= 0.2 kg/cm2/1000 m

Pr. loss =

56 kg/cm2

= 0.0112 kg/cm

Step: 8

Determine pressure loss through drill collar bore

Pressure loss for entire drill = Length of drill collar


59/95

54 | P a g e

collar bore


Drill collar = 8 3

Pr. Loss through D/C bore of 3 = 16.7 kg/cm2/1000 m

Total Pr. Loss thorough

D/C bore =

56 kg/cm2

= .9352 kg/cm2

Drill collar =

Pr. Loss through D/C bore of

= 22.8 kg/cm /1000 m


D/C bore =

56 kg/cm2

= 12.768 kg/cm

Total Pr. Loss thorough D/C

bore = .9352 + 12.768 kg/cm2

= 13.7032 kg/cm

Step: 9

Determine Pressure loss in Drill Collar Annulus


collar annulus

=

Length of drill collar


Pr. Loss through D/C annulus

of 3 = .33908 kg/cm2


60/95

55 | P a g e

Pr. Loss through D/C

Annulus of

= .10304 kg/cm


annulus = .33908 + .10304 kg/cm2

Step: 10

= .44212 kg/cm

Actual system pressure loss =

System pressure loss

Total Pr. loss = 6.94 + 1.5568 + 0.0112 + 13.702 + 0.44212 kg/cm2

= 22.65 kg/cm

Actual System Pressure loss = 22.65

kg/cm2

= 19.82 kg/cm2

Step: 11

Pressure available for nozzle selection is the difference is the difference between the Operating

Pressure Limit and the actual system pressure loss, corrected to 1.2 sp. gr.

Pressure available for nozzle

selection

= (Step 2 minus Step 10)

Pressure available = (10019.82)

kg/cm

2= 91.6323 kg/cm

2

Step: 12

Using the established circulation rate, select a jet nozzle size combination for which the pressure loss

is equal to or less than the amount of pressure available (see Step-11)


61/95

56 | P a g e

Nozzle size - 17-17-18

Pr. drop = 85 kg/cm2

Step: 13

Actual Pr. loss = 85

kg/cm

2

= 75.375 kg/cm

Step: 14

Stand Pipe Pressure = System pressure loss excluding nozzle + pressure loss

thorough the nozzles

Stand pipe pressure = 75.375 +19.82 kg/cm2

= 94.195 kg/cm

Step: 15

Percentage of hydraulic horsepower available at bit

%BHP =

%BHP =

= 80.02%

Step: 16

Jet velocity =

Jet velocity =

m/sec

= 104.02 m/sec

Step: 17

BHHP/ sq. inch hole size =


m/sec


62/95

57 | P a g e

= 2.0613 m/sec

SECTION: 2

Hole Size = 12

inches

Mud weight = 1.18


Drill Collar = 8 3 = 28 m

6

2

= 112 m



Step: 1


Hole size = 12

inches



= 33 m/min

= 0.55 m/sec

Step: 2

Table D-3 contains the pressure ratings (kg/cm2) and volumetric discharge (in litres per stroke) for



Liner size =

No. of pumps = 2



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Step: 3


SPM = 80 2

Step: 4



Step: 5





equipment

= 3.57 kg/cm2

Step6



pipe string

=



bore

= 14.3 kg/cm2/1000 m


drill pipe string

=

1404 kg/cm2

= 20.077 kg/cm2

Step: 7


For 12



annulus

= 0.4 kg/cm2/1000 m

Pr. Loss =

1404 kg/cm2


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= 0.5616 kg/cm

Step: 8



collar bore

=



Drill collar = 8 3



D/C bore =

28 kg/cm2

= 2.408 kg/cm

Drill collar =


= 11.7 kg/cm2/1000 m


D/C bore =

112 kg/cm2

= 13.104 kg/cm2


bore = 2.408 + 13.104 kg/cm2

= 15.512 kg/cm

Step: 9



collar annulus

=




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Drill collar = 8 3

Pr. Loss through D/C annulus = 0.23 kg/cm2/100 m


D/C bore =

28 kg/cm2

= 0.0644 kg/cm

Drill collar =

Pr. Loss through D/C annulus = 0.23 kg/cm /100 m


D/C annulus =

112 kg/cm2

= 0.258 kg/cm2

Total Pr. Loss through D/C

annulus = 0.258 + 0.0644 kg/cm2

= 0.3224

Step: 10

Add values obtained in Steps 5, 6 ,7 ,8 and 9 to obtain total pressure loss (excluding nozzles)

Actual system pressure loss = System pressure loss

Total Pr. Loss = 3.57 + 20.077 + 0.5616 + 15.512 + 0.3224 kg/cm2

= 40.043 kg/cm2


kg/cm2

= 39.38 kg/cm

Step: 11




selection



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selection

= (10039.38)

kg/cm

2= 61.64 kg/cm

2

Step: 12




Pr. Drop = 57.4 kg/cm2

Step: 13

Actual Pr. Loss = 57.4

kg/cm

2

= 56.44 kg/cm

Step: 14



Stand pipe pressure = 56.4 + 39.38 kg/cm

= 95.82 kg/cm

Step: 15


%BHP =

%BHP =

= 58.86%

Step: 16


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Jet velocity =

Jet velocity =

m/sec

= 92.105 m/sec

Step: 17



m/sec

= 2.203 m/sec

SECTION: 3

Hole Size = 8

inches

Mud weight = 1.28


Drill Collar 6

2

= 168 m



Step: 1


Hole size = 8

inches



= 54 m/min


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= 0.9 m/sec

Step: 2

Table D-3 contains the pressure ratings (kg/cm ) and volumetric discharge (in litres per stroke) for



Liner size =

No. of pumps = 2

Operating Pressure Limit = 90 kg/cm

Step: 3


SPM = 110

Step: 4



Step: 5





equipment

= 2.68 kg/cm

Step6



pipe string

=



bore

= 10.8 kg/cm /1000 m


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= 2.53 kg/cm2/100

Pressure loss through D/C

annulus =

168 kg/cm2

= 4.25 kg/cm2

Step: 10



Total Pr. Loss = 2.68 + 31.95 + 16.86 + 14.784 + 4.25 kg/cm2

= 70.524 kg/cm


kg/cm

2

= 75.23 kg/cm2

Step: 11




selection


Pressure available for

nozzle selection

= (9075.23)

kg/cm

2= 13.85 kg/cm

2

Step: 12Using the established circulation rate, select a jet nozzle size combination for which the pressure loss



Pr. drop = 16 kg/cm2

Step: 13


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kg/cm

2

= 16.8 kg/cm

Step: 14



Stand pipe pressure = 16.8 + 72.42 kg/cm2

= 89.22 kg/cm

Step: 15Percentage of hydraulic horsepower available at bit

%BHP =

%BHP =

= 18.83 %

Step: 16

Jet velocity =

Jet velocity =

m/sec

= 50.52 m/sec

Step: 17



m/sec

= 1.168 m/sec


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Step: 5





equipment

= 6.94 kg/cm

Step - 6



pipe string

=



bore

= 27.8 kg/cm /1000 m


drill pipe string

= 56 kg/cm

2

= 1.5568 kg/cm2

Step: 7


For 17



annulus

= 0.2 kg/cm2/1000 m

Pr. loss =

56 kg/cm2

= 0.0112 kg/cm2

Step: 8



collar bore

=



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Drill collar = 8 3

Pr. Loss through D/C bore of 3 = 16.7 kg/cm /1000 m


D/C bore =

28 kg/cm2

= 4.676 kg/cm2

Drill collar =


= 22.8 kg/cm /1000 m


D/C bore =

56 kg/cm2

= 12.768 kg/cm


bore = 4.676 + 12.768 kg/cm2

= 17.444 kg/cm

Step: 9



collar annulus

=




of 3 = .33908 kg/cm2

Pr. Loss through D/C

Annulus of

= .10304 kg/cm2


annulus = .33908 + .10304 kg/cm

2


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Step: 10

= .44212 kg/cm2


Total Pr. loss = 6.94 + 1.5568 + 0.0112 + 17.444 + 0.44212 kg/cm

= 26.39412 kg/cm2


kg/cm

2

= 23.09 kg/cm2

Step: 11




selection


Pressure available = (13023.09)

kg/cm

2= 122.182 kg/cm

2

Step: 12Using the established circulation rate, select a jet nozzle size combination for which the pressure loss



Pr. drop = 117.2 kg/cm2

Step: 13

Actual Pr. loss = 117.2

kg/cm2


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= 102.54 kg/cm

Step: 14



Stand pipe pressure = 102.54 +23.09 kg/cm2

= 125.63 kg/cm

Step: 15


%BHP =

%BHP =

= 81.62 %

Step: 16

Jet velocity =

Jet velocity =

m/sec

= 131.57 m/sec

Step: 17



m/sec

= 2.8042 m/sec

SECTION: 2

Hole Size = 12

inches

Mud weight = 1.20


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Drill Collar = 8 3 = 28 m

6

2

= 112 m



Step: 1


Hole size = 12

inches



= 33 m/min

= 0.55 m/sec

Step: 2Table D-3 contains the pressure ratings (kg/cm ) and volumetric discharge (in litres per stroke) for



Liner size =

No. of pumps = 2


Step: 3


SPM = 80 2

Step: 4




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Step: 5





equipment

= 3.57 kg/cm2

Step - 6



pipe string

=



bore

= 14.3 kg/cm2/1000 m


drill pipe string

=

1604 kg/cm2

= 22.937 kg/cm2

Step: 7


For 12



annulus

= 0.4 kg/cm2/1000 m

Pr. loss =

1604 kg/cm2

= 0.6416 kg/cm2

Step: 8



collar bore

=




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Drill collar = 8 3



D/C bore =

28 kg/cm2

= 2.408 kg/cm

Drill collar =


= 11.7 kg/cm2/1000 m


D/C bore =

112 kg/cm2

= 13.104 kg/cm


bore = 2.408 + 13.104 kg/cm2

= 15.512 kg/cm2

Step: 9



collar annulus

=



Drill collar = 8 3

Pr. Loss through D/C annulus = 0.23 kg/cm2/100 m


D/C bore =

28 kg/cm2

= 0.0644 kg/cm

Drill collar =

Pr. Loss through D/C annulus = 0.23 kg/cm /100 m


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D/C annulus =

112 kg/cm2

= 0.258 kg/cm

Total Pr. Loss through D/C

annulus = 0.258 + 0.0644 kg/cm2

= 0.3224

Step: 10



Total Pr. loss = 3.57 + 22.937 + 0.6416 + 15.512 + 0.3224 kg/cm

= 42.983 kg/cm2


kg/cm2

= 42.983 kg/cm

Step: 11




selection



selection

= (10042.983)

kg/cm

2= 57.027 kg/cm

2

Step: 12




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Pr. drop = 52.6 kg/cm2

Step: 13

Actual Pr. loss = 52.6

kg/cm

2

= 52.6 kg/cm

Step: 14



Stand pipe pressure = 52.6 + 42.983 kg/cm

= 95.583 kg/cm

Step: 15


%BHP =

%BHP =

= 55.03%

Step: 16

Jet velocity =

Jet velocity =

m/sec

= 92.267 m/sec

Step: 17


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m/sec

= 2.06 m/sec

SECTION: 3

Hole Size = 8

inches

Mud weight = 1.26


Drill Collar 6

2

= 168 m



Step: 1


Hole size = 8

inches



= 54 m/min

= 0.9 m/sec

Step: 2

Table D-3 contains the pressure ratings (kg/cm2) and volumetric discharge (in litres per stroke) for



Liner size =


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No. of pumps = 2


Step: 3


SPM = 110

Step: 4



Step: 5





equipment

= 2.68 kg/cm

Step - 6



pipe string

=



bore

= 10.8 kg/cm /1000 m

Pressure loss thorough entiredrill pipe string

=

2868 kg/cm2

= 30.97 kg/cm2

Step: 7


For 8



annulus

= 5.7 kg/cm2/1000 m


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Pr. loss =

2868 kg/cm2

= 16.3476 kg/cm

Step: 8



collar bore

=



Drill collar =


= 8.8 kg/cm2

/1000 m


D/C bore =

168 kg/cm2

= 14.784 kg/cm

Step: 9



collar annulus

=




= 2.53 kg/cm2/100

Pressure loss through D/C

annulus =

168 kg/cm2

= 4.25 kg/cm

Step: 10




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Total Pr. loss = 2.68 + 30.97 + 16.3476 + 14.784 + 4.25 kg/cm2

= 69.0316 kg/cm2


kg/cm

2

= 72.48 kg/cm

Step: 11



Pressure available for nozzleselection


Pressure available for

nozzle selection

= (9072.48)

kg/cm

2= 16.59 kg/cm

2

Step: 12




Pr. drop = 16 kg/cm

Step: 13


kg/cm

2

= 16.8 kg/cm

Step: 14



Stand pipe pressure = 16.8 + 72.42 kg/cm2

= 89.22 kg/cm


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Step: 15


%BHP =

%BHP =

= 18.83 %

Step: 16

Jet velocity =

Jet velocity = m/sec

= 50.52 m/sec

Step: 17



m/sec

= 1.168 m/sec


87/95

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7.CEMENTINGCement is used primarily as an impermeable seal material in oil and gas well drilling. It is

most widely used as a seal between casing and the borehole, bonding the casing to the

formation and providing a barrier to the flow of fluids from, or into, the formations behindthe casing and from, or into, the subsequent hole section. Cement is also used for remedial or

repair work on producing wells. It is used for instance to seal off perforated casing when a

producing zone starts to produce a large amount of water and/or to repair casing leaks.

Functions of Oil Well Cement

The most important functions of a cement sheath between the casing and the borehole are:

a) To prevent the movement of fluids from one formation to another or from the

formations to surface through the annulus between the casing and the borehole.

b) To support the casing string (specifically surface casing)

c) To protect the casing from corrosive fluids in the formations.

However, the prevention of fluid migration is by far the most important function of the

cement sheath between the casing and the borehole. Cement is only require to support the

casing in the case of surface casing where the axial loads on the casing, due to the weight of

the installed Wellhead and BOP connected to the top of the casing, are extremely high.

7.1.PRIMARY CEMENTING

The objective of a primary cement job is to place the cement slurry in the annulus behind the

casing. In most cases this can be done in a single operation, by pumping cement down the

casing, through the casing shoe and up into the annulus. However, in longer casing strings

and in particular where the formations are weak and may not be able to support the

hydrostatic pressure generated by a very long column of cement slurry, the cement job may

be carried out in two stages.

The first stage is completed in the manner described above, with the exception that the

cement slurry does not fill the entire annulus, but reaches only a pre-determined height above

the shoe. The second stage is carried out by including a special tool in the casing string which

can be opened, allowing cement to be pumped from the casing into the annulus. The tool is

called a multi stage cementing tool and is placed in the casing string at the point at which the

bottom of the second stage is required. This is known as a two stage cementing operation.

7/29/2019 Drilling Plan Anlaysis and Comp

Drilling Plan Anlaysis and Comparison of two directional well of Gandhar Field

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