drilling plan anlaysis and comparison of two directional well of gandhar field
TRANSCRIPT
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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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(i)
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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(ii)
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
A graph has been plotted from above table.
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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:
A graph has been plotted from above table.
Collapse Criteria :
A graph has been plotted from above table.
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
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4.5.5. PRODUCTION CASING :Packer fluid density = 9 lb/gal
FBHP = 2000psi
Burst Criteria:
A graph has been plotted from above table.
Collapse Criteria:
A graph has been plotted from above table.
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
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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
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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
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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
2727 1.26 61 13-Jun -SAND + SILT +SHALE
2796 1.26 60 14-Jun -SAND + 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.
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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
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Fig.10: Plot between Pressure (ppg) V/S Depth(m), indicating the casing shoes
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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(
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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
A graph has been plotted from above table.
Collapse Criteria:
Load Backup Resultant Design
cement length 200 491.1679 0 491.1679 540.2847
mud length 0 0 0 0 0
A graph has been plotted from above table.
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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
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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
A graph has been plotted from above table.
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
A graph has been plotted from above table.
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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
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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
A graph has been plotted from above table.
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
A graph has been plotted from above table.
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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
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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
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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
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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
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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
Mud weight 1.2 gm/cc 10.02ppg
Buoyancy factor = 1-(MW/65.5)
=1-(10.02/65.5)
=0.847
Safety factor =0.8
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WOB = 15 tons
Weght of drill collar in air = WOB/ ( S.FB.FCOS )
= 15/ (0.80.866COS 7.6)
= 22.33 tons
Available drill collar are:-
Size Length of one stand Weight of on stand
8 3 28m 6.1 tons
16 2 13/16 112m 15.28tons
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 .1tons 2 12.2tons
16 2 13/16 15.28 tons 1 15.28 tons
Total weight of drillcollar
27 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 weight of drill collar and HWDP is
= 13 + 4 tons
= 80 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,
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PA = Theoretical Yield Strength.
Yt= Drill Pipe Yield Strength.
BF = Buoyancy Factor.
SF = Safety Factor.
Ldp =
Ldp = 141.78 0.910^3/ ( 0.8 0.847 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
Buoyancy factor = 1-(MW/65.5)
=1-(8.76/65.5)
=0.83
Safety factor =0.8
WOB = 25 tons
Weght of drill collar in air = WOB/ ( S.FB.FCOS )
= 25/ (0.80.83COS23 )
= 51 tons
Available drill collar are :-
Size Length of one stand Weight of on stand
8 3 56 m 6 tons
16 2 13/16 168m 22.8tons
Adjusting the sizes of the drill collars to their effective WOB
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Size Weight of one stand 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
Total weight of drillcollar
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
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 0.83 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)
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= 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
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
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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
Nominal weight of HWDP = 71.41 Kg/m
Weight of one HWDP =71.41 56 = 4 tons
Total weght 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 1810m
Hole size 12 in
Mud weight 1.2 gm/cc 10.02ppg
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Buoyancy factor = 1-(MW/65.5)
=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
Available drill collar are :-
Size Length of one stand Weight of on stand
8 3 28m 6.1 tons
16 2 13/16 112m 15.28tons
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 .1tons 2 12.2tons
16 2 13/16 15.28 tons 1 15.28 tons
Total weight of drillcollar
27 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
= 13 + 4 tons
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= 80 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 0.847 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
Buoyancy factor = 1-(MW/65.5)
=1-(8.76/65.5)
=0.83
Safety factor =0.8
WOB = 25 tons
Weight of drill collar in air = WOB/ ( S.FB.FCOS )
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= 25/ (0.80.83COS23 )
= 51 tons
Available drill collar are :-
Size Length of one stand Weight of on stand
8 3 56 m 6 tons
16 2 13/16 168m 22.8tons
Adjusting the sizes of the drill collars to their effective WOB
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
Total weight of drillcollar
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
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.
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BF = Buoyancy Factor.
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
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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.
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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
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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
Circulation rate = 3000 LPM
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
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collar bore
Circulation rate = 3000 LPM
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
Total Pr. Loss thorough
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
Pressure loss for entire drill
collar annulus
=
Length of drill collar
Circulation rate = 3000 LPM
Pr. Loss through D/C annulus
of 3 = .33908 kg/cm2
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Pr. Loss through D/C
Annulus of
= .10304 kg/cm
Total Pr. Loss thorough D/C
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)
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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 =
BHHP/ sq. inch hole size =
m/sec
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= 2.0613 m/sec
SECTION: 2
Hole Size = 12
inches
Mud weight = 1.18
Depth interval = 0 m to 1600 m
Drill Collar = 8 3 = 28 m
6
2
= 112 m
Drill Pipe = 5 Gd E 19.5 ppf XH = 1404 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 = 12
inches
Circulation rate = 2100 LPM
Annular velocity = 110 ft/min
= 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
various models of pumps using different liner sizes. Discharge is based on 100% volumetric
efficiency of the pumps
Liner size =
No. of pumps = 2
Operating Pressure Limit = 100 kg/cm2
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Step: 3
With the pump output found in Table D-3 and the circulation rate (l/min) selected, calculate SPM
SPM = 80 2
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
Circulation rate = 2100 LPM
Pressure Losses through surface
equipment
= 3.57 kg/cm2
Step6
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
= 14.3 kg/cm2/1000 m
Pressure loss thorough entire
drill pipe string
=
1404 kg/cm2
= 20.077 kg/cm2
Step: 7
Determine pressure loss in drill pipe annulus
For 12
inches hole size and 5 drill pipe
Pr. Loss through drill pipe
annulus
= 0.4 kg/cm2/1000 m
Pr. Loss =
1404 kg/cm2
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= 0.5616 kg/cm
Step: 8
Determine pressure loss through drill collar bore
Pressure loss for entire drill
collar bore
=
Length of drill collar
Circulation rate = 2100 LPM
Drill collar = 8 3
Pr. Loss through D/C bore of 3 = 8.6 kg/cm2/1000 m
Total Pr. Loss thorough
D/C bore =
28 kg/cm2
= 2.408 kg/cm
Drill collar =
Pr. Loss through D/C bore of
= 11.7 kg/cm2/1000 m
Total Pr. Loss thorough
D/C bore =
112 kg/cm2
= 13.104 kg/cm2
Total Pr. Loss thorough D/C
bore = 2.408 + 13.104 kg/cm2
= 15.512 kg/cm
Step: 9
Determine Pressure loss in Drill Collar Annulus
Pressure loss for entire drill
collar annulus
=
Length of drill collar
Circulation rate = 2100 LPM
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Drill collar = 8 3
Pr. Loss through D/C annulus = 0.23 kg/cm2/100 m
Total Pr. Loss thorough
D/C bore =
28 kg/cm2
= 0.0644 kg/cm
Drill collar =
Pr. Loss through D/C annulus = 0.23 kg/cm /100 m
Total Pr. Loss thorough
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
Actual System Pressure loss = 40.043
kg/cm2
= 39.38 kg/cm
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)
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Pressure available for nozzle
selection
= (10039.38)
kg/cm
2= 61.64 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)
Nozzle size - 16-16-16
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 = System pressure loss excluding nozzle + pressure loss
thorough the nozzles
Stand pipe pressure = 56.4 + 39.38 kg/cm
= 95.82 kg/cm
Step: 15
Percentage of hydraulic horsepower available at bit
%BHP =
%BHP =
= 58.86%
Step: 16
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Jet velocity =
Jet velocity =
m/sec
= 92.105 m/sec
Step: 17
BHHP/ sq. inch hole size =
BHHP/ sq. inch hole size =
m/sec
= 2.203 m/sec
SECTION: 3
Hole Size = 8
inches
Mud weight = 1.28
Depth interval = 0 m to 3177 m
Drill Collar 6
2
= 168 m
Drill Pipe = 5 Gd E 19.5 ppf XH = 2958 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 = 8
inches
Circulation rate = 1800 LPM
Annular velocity = 180 ft/min
= 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
various models of pumps using different liner sizes. Discharge is based on 100% volumetric
efficiency of the pumps
Liner size =
No. of pumps = 2
Operating Pressure Limit = 90 kg/cm
Step: 3
With the pump output found in Table D-3 and the circulation rate (l/min) selected, calculate SPM
SPM = 110
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
Circulation rate = 1800 LPM
Pressure Losses through surface
equipment
= 2.68 kg/cm
Step6
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
= 10.8 kg/cm /1000 m
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Pr. Loss through D/C annulus
= 2.53 kg/cm2/100
Pressure loss through D/C
annulus =
168 kg/cm2
= 4.25 kg/cm2
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 = 2.68 + 31.95 + 16.86 + 14.784 + 4.25 kg/cm2
= 70.524 kg/cm
Actual System Pressure loss = 70.524
kg/cm
2
= 75.23 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 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
is equal to or less than the amount of pressure available (see Step-11)
Nozzle size - 18-20-20
Pr. drop = 16 kg/cm2
Step: 13
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Actual Pr. loss = 16
kg/cm
2
= 16.8 kg/cm
Step: 14
Stand Pipe Pressure = System pressure loss excluding nozzle + pressure loss
thorough the nozzles
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
BHHP/ sq. inch hole size =
BHHP/ sq. inch hole size =
m/sec
= 1.168 m/sec
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Select surface equipment
Surface equipment - Type 3
Step: 5
See Pressure Losses through surface equipment from Table D-5
For surface equipment Type -3
Circulation rate = 3000 LPM
Pressure Losses through surface
equipment
= 6.94 kg/cm
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/cm /1000 m
Pressure loss thorough entire
drill pipe string
= 56 kg/cm
2
= 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/cm2
Step: 8
Determine pressure loss through drill collar bore
Pressure loss for entire drill
collar bore
=
Length of drill collar
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Circulation rate = 3000 LPM
Drill collar = 8 3
Pr. Loss through D/C bore of 3 = 16.7 kg/cm /1000 m
Total Pr. Loss thorough
D/C bore =
28 kg/cm2
= 4.676 kg/cm2
Drill collar =
Pr. Loss through D/C bore of
= 22.8 kg/cm /1000 m
Total Pr. Loss thorough
D/C bore =
56 kg/cm2
= 12.768 kg/cm
Total Pr. Loss thorough D/C
bore = 4.676 + 12.768 kg/cm2
= 17.444 kg/cm
Step: 9
Determine Pressure loss in Drill Collar Annulus
Pressure loss for entire drill
collar annulus
=
Length of drill collar
Circulation rate = 3000 LPM
Pr. Loss through D/C annulus
of 3 = .33908 kg/cm2
Pr. Loss through D/C
Annulus of
= .10304 kg/cm2
Total Pr. Loss thorough D/C
annulus = .33908 + .10304 kg/cm
2
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Step: 10
= .44212 kg/cm2
Actual system pressure loss = System pressure loss
Total Pr. loss = 6.94 + 1.5568 + 0.0112 + 17.444 + 0.44212 kg/cm
= 26.39412 kg/cm2
Actual System Pressure loss = 26.39412
kg/cm
2
= 23.09 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 = (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
is equal to or less than the amount of pressure available (see Step-11)
Nozzle size - 16-16-16
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 = System pressure loss excluding nozzle + pressure loss
thorough the nozzles
Stand pipe pressure = 102.54 +23.09 kg/cm2
= 125.63 kg/cm
Step: 15
Percentage of hydraulic horsepower available at bit
%BHP =
%BHP =
= 81.62 %
Step: 16
Jet velocity =
Jet velocity =
m/sec
= 131.57 m/sec
Step: 17
BHHP/ sq. inch hole size =
BHHP/ sq. inch hole size =
m/sec
= 2.8042 m/sec
SECTION: 2
Hole Size = 12
inches
Mud weight = 1.20
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Depth interval = 0 m to 1800 m
Drill Collar = 8 3 = 28 m
6
2
= 112 m
Drill Pipe = 5 Gd E 19.5 ppf XH = 1604 m
Pump available = A-1100-PT, 2 Nos.
Step: 1
Select Circulation rate for particular annular size and hole size from table D-1
Hole size = 12
inches
Circulation rate = 2100 LPM
Annular velocity = 110 ft/min
= 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
various models of pumps using different liner sizes. Discharge is based on 100% volumetric
efficiency of the pumps
Liner size =
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 = 80 2
Step: 4
Select surface equipment
Surface equipment - Type 3
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Step: 5
See Pressure Losses through surface equipment from Table D-5
For surface equipment Type -3
Circulation rate = 2100 LPM
Pressure Losses through surface
equipment
= 3.57 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
= 14.3 kg/cm2/1000 m
Pressure loss thorough entire
drill pipe string
=
1604 kg/cm2
= 22.937 kg/cm2
Step: 7
Determine pressure loss in drill pipe annulus
For 12
inches hole size and 5 drill pipe
Pr. Loss through drill pipe
annulus
= 0.4 kg/cm2/1000 m
Pr. loss =
1604 kg/cm2
= 0.6416 kg/cm2
Step: 8
Determine pressure loss through drill collar bore
Pressure loss for entire drill
collar bore
=
Length of drill collar
Circulation rate = 2100 LPM
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Drill collar = 8 3
Pr. Loss through D/C bore of 3 = 8.6 kg/cm2/1000 m
Total Pr. Loss thorough
D/C bore =
28 kg/cm2
= 2.408 kg/cm
Drill collar =
Pr. Loss through D/C bore of
= 11.7 kg/cm2/1000 m
Total Pr. Loss thorough
D/C bore =
112 kg/cm2
= 13.104 kg/cm
Total Pr. Loss thorough D/C
bore = 2.408 + 13.104 kg/cm2
= 15.512 kg/cm2
Step: 9
Determine Pressure loss in Drill Collar Annulus
Pressure loss for entire drill
collar annulus
=
Length of drill collar
Circulation rate = 2100 LPM
Drill collar = 8 3
Pr. Loss through D/C annulus = 0.23 kg/cm2/100 m
Total Pr. Loss thorough
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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Total Pr. Loss thorough
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
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 + 22.937 + 0.6416 + 15.512 + 0.3224 kg/cm
= 42.983 kg/cm2
Actual System Pressure loss = 42.983
kg/cm2
= 42.983 kg/cm
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 for nozzle
selection
= (10042.983)
kg/cm
2= 57.027 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)
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Nozzle size - 16-16-17
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 = System pressure loss excluding nozzle + pressure loss
thorough the nozzles
Stand pipe pressure = 52.6 + 42.983 kg/cm
= 95.583 kg/cm
Step: 15
Percentage of hydraulic horsepower available at bit
%BHP =
%BHP =
= 55.03%
Step: 16
Jet velocity =
Jet velocity =
m/sec
= 92.267 m/sec
Step: 17
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BHHP/ sq. inch hole size =
BHHP/ sq. inch hole size =
m/sec
= 2.06 m/sec
SECTION: 3
Hole Size = 8
inches
Mud weight = 1.26
Depth interval = 0 m to 3092 m
Drill Collar 6
2
= 168 m
Drill Pipe = 5 Gd E 19.5 ppf XH = 2868 m
Pump available = A-1100-PT, 2 Nos.
Step: 1
Select Circulation rate for particular annular size and hole size from table D-1
Hole size = 8
inches
Circulation rate = 1800 LPM
Annular velocity = 180 ft/min
= 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
various models of pumps using different liner sizes. Discharge is based on 100% volumetric
efficiency of the pumps
Liner size =
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No. of pumps = 2
Operating Pressure Limit = 90 kg/cm2
Step: 3
With the pump output found in Table D-3 and the circulation rate (l/min) selected, calculate SPM
SPM = 110
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
Circulation rate = 1800 LPM
Pressure Losses through surface
equipment
= 2.68 kg/cm
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
= 10.8 kg/cm /1000 m
Pressure loss thorough entiredrill pipe string
=
2868 kg/cm2
= 30.97 kg/cm2
Step: 7
Determine pressure loss in drill pipe annulus
For 8
inches hole size and 5 drill pipe
Pr. Loss through drill pipe
annulus
= 5.7 kg/cm2/1000 m
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Pr. loss =
2868 kg/cm2
= 16.3476 kg/cm
Step: 8
Determine pressure loss through drill collar bore
Pressure loss for entire drill
collar bore
=
Length of drill collar
Circulation rate = 1800 LPM
Drill collar =
Pr. Loss through D/C bore of
= 8.8 kg/cm2
/1000 m
Total Pr. Loss thorough
D/C bore =
168 kg/cm2
= 14.784 kg/cm
Step: 9
Determine Pressure loss in Drill Collar Annulus
Pressure loss for entire drill
collar annulus
=
Length of drill collar
Circulation rate = 1800 LPM
Pr. Loss through D/C annulus
= 2.53 kg/cm2/100
Pressure loss through D/C
annulus =
168 kg/cm2
= 4.25 kg/cm
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
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Total Pr. loss = 2.68 + 30.97 + 16.3476 + 14.784 + 4.25 kg/cm2
= 69.0316 kg/cm2
Actual System Pressure loss = 69.0316
kg/cm
2
= 72.48 kg/cm
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 nozzleselection
= (Step 2 minus Step 10)
Pressure available for
nozzle selection
= (9072.48)
kg/cm
2= 16.59 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)
Nozzle size - 18-20-20
Pr. drop = 16 kg/cm
Step: 13
Actual Pr. loss = 16
kg/cm
2
= 16.8 kg/cm
Step: 14
Stand Pipe Pressure = System pressure loss excluding nozzle + pressure loss
thorough the nozzles
Stand pipe pressure = 16.8 + 72.42 kg/cm2
= 89.22 kg/cm
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Step: 15
Percentage of hydraulic horsepower available at bit
%BHP =
%BHP =
= 18.83 %
Step: 16
Jet velocity =
Jet velocity = m/sec
= 50.52 m/sec
Step: 17
BHHP/ sq. inch hole size =
BHHP/ sq. inch hole size =
m/sec
= 1.168 m/sec
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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.
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