Q931+de1 reference en lecs

Drilling Engineering 1 Course
3rd Ed. , 3rd Experience

1. About This Course
2. Course Learning Outcome
3. Presentation and assessment
A. Class Projects (CLS PRJ)
4. Review of Syllabus
5. Resources
6. Training Outline (beta)
7. Communication

A quote on Beginnings
"Before you begin a thing, remind yourself that
difficulties and delays quite impossible to foresee
are ahead.
If you could see them clearly, naturally you could do
a great deal to get rid of them but you can't.
You can only see one thing clearly and
that is your goal.
Form a mental vision of that and
cling to it through thick and thin"
Kathleen Norris
Fall 14 H. AlamiNia Drilling Engineering 1 Course (3rd Ed.) 4

Course Scope
Systematic theoretical
and practical study of
drilling engineering;

Course Description
This course is prepared for:
 3 semester (or credit) hours and meets
for a total of 3 hours a week.
Sophomore or junior level students (BS degrees)
(Major) Petroleum engineering students
(Minors) Production, Drilling and reservoir engineering students
Prerequisites:
Fluid mechanics
Main objectives:

Learning and Teaching Strategies
This course promotes interactive and thorough
engagement in the learning process.
It is essential that you take responsibility for your
own learning, and that I facilitate that learning by
establishing a supportive as well as challenging
environment.

Proposed study method
When studying petroleum engineering,
it is important to realize that
the things you are learning today
will be important to you for the rest of your career.
Hence,
you shouldn’t just learn things simply to pass exams!
You will gain maximum benefit from this course by
approaching each lecture and in-class activity
with an inquiring mind and a critical, analytical attitude.

Study recommendations
In covering the material in the course, I recommend
that you follow the procedure outlined below:
Carefully read the entire chapter
to familiarize yourself with the material.
Locate the topic area in your text book and study this material
in conjunction with the course material.
Attempt the examples before all tutorials.
When you feel that you have mastered a topic area,
attempt the problem for the topic.
You are required to complete the assigned readings prior to
lectures.
This will help your active participation in class activities.
Self-study in advance is always more beneficial.

Main Objectives (minimum skills to be
achieved/demonstrated)
By the last day of class,
the student should be able to:

Minor Objectives (other skills to be
achieved/demonstrated)

Side Objectives
Communicational skills
Communicate
successfully and
effectively.
Understand professional
and ethical
responsibilities.
Work in a team
environment
Familiarize with English
language
Academic skills
Systematic research
Reporting
Management skills
Project
time
Computer knowledge
Understand the use of
modern techniques, skills
and modern engineering
tools
Application of internet
and Email
Microsoft Office
Professional software

Presentations (Lectures)
Each session
Consists of different sections (about 4-5 sections)
Consists of about 35 slides
Is divided into 2 parts with short break time
Would be available online
The teaching approach to be employed will involve
lectures and tutorials.
Lecture presentations cover theoretical and practical
aspects, which are also described in the supporting
academic texts and teaching resources.
You are encouraged to ask questions and express feedback
during classes. You are expected to read prescribed materials
in advance of classes to enable active participation.

Timing
Last Session (Review)
Areas Covered in This
Lecture
Presentation A
Break Time
Presentation B
Next Session Topics
Last session
(Review)
Session
Outlook
Presentation ABreak
Time
Presentation B
Next Session
Topics
Roll Call

Assessment Criteria
Basis for Course Grade:
Final exam
(Close book)
Attendance
Class activities
Class Projects
Examinations
Grade Range:
90 ≤ A ≤100 (18 ≤ A ≤20)
80 ≤ B ≤ 90 (16 ≤ B ≤18)
70 ≤ C ≤ 80 (14 ≤ C ≤16)
60 ≤ D ≤ 70 (12 ≤ D ≤14)
F < 60 (F <12)
Final
exam
Attendance
Class
activities

Previous Term Scores out of 20 (Q922)
10.0
15.0
20.0
F DE1 F DE2 F LOG F RE2 F RFP

Previous Term (Q922)
Attendance percentage
Students are
expected to
be regular and
punctual in
attendance at
all lectures
and tutorials.
Attendance
will be
recorded
when
applicable.
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
DE1 DE2 LOG RE2 RFP

CLS PRJ Topics:
These are intended
topics, addition and/or
deletion of certain
problems may occur as
other problems become
available. Multiple
assignments from each
topic are possible.

Format of the Report:
 Title page:
 Course number, course name,
Experiment number & title, Lab date,
Names of the lab group
 Sections to include in each report
 Introduction
 Objective/purpose of the experiment
 Scope of the experiment / Importance
of the parameters measured
 How (in general) you obtained the
information you are reporting
 Methods
 Describe Equipment
 Experimental procedure (write it in your
own words)
 Methods of analysis (if appropriate)
 How did you analyze the data (principle
/ equations used)
 Results:
 State/tabulate/plot results as applicable
 Report both observed and measured
results
 Discussion:
 Discuss the importance of results
 Tie the results of this study to previous
knowledge/works
 Comment on the quality of results
 Conclusions:
 Findings in the study (stick to the results
you measured)
 References
 Appendices
 Raw Data tables
 Must include sample calculations
 Derivation of equations (if applicable)
 Report late submission Policy:
 Report must be submitted one week
after experiment unless asked
otherwise. Deduction of 10% grade per
late submission will be applied.

Deliverable Format Guidelines
General Instructions:
You must use predefined templates for reporting the
projects
Follow predefine instructions

‫حفاری‬ ‫مهندسی‬ ‫درس‬ ‫سرفصل‬(1)
(‫علوم‬ ‫وزارت‬ ‫مصوب‬1390)
‫مقدمه‬:
‫و‬ ‫حفاری‬ ‫عملیات‬ ‫اجمالی‬ ‫بررسی‬
‫توسعه‬ ‫مختلف‬ ‫مراحل‬ ‫آن‬ ‫اهمیت‬
‫حفاری‬ ‫نقش‬ ‫و‬ ‫میدان‬
‫چاهها‬ ‫انواع‬ ‫بندی‬ ‫تقسیم‬
‫در‬ ‫حفاری‬ ‫پرسنل‬ ‫معرفی‬
‫شرکت‬‫کار‬ ‫پیمان‬ ‫و‬ ‫کارفرما‬ ‫های‬
‫دهنده‬ ‫سرویس‬ ‫شرکتهای‬ ‫وظایف‬
‫حفاری‬ ‫اقتصاد‬
‫دکل‬ ‫حفاری‬ ‫قراردادهای‬ ‫انواع‬‫های‬
‫حفاری‬
‫حفاری‬ ‫دکل‬
‫دکل‬ ‫انواع‬ ‫بندی‬ ‫دسته‬‫حفاری‬ ‫های‬
‫فراساحلی‬ ‫و‬ ‫خشکی‬ ‫در‬
‫دکل‬ ‫انتخاب‬ ‫نحوه‬‫در‬ ‫حفاری‬ ‫های‬
‫دریا‬ ‫و‬ ‫خشکی‬
‫و‬ ‫حفاری‬ ‫دکلهای‬ ‫اصلی‬ ‫اجزائ‬
‫جزء‬ ‫هر‬ ‫اصلی‬ ‫محاسبات‬:
‫نیرو‬ ‫مولد‬ ‫سیستم‬
‫برنده‬ ‫باال‬ ‫سیستم‬
‫حف‬ ‫گل‬ ‫تصفیه‬ ‫و‬ ‫گردش‬ ‫سیستم‬‫اری‬
‫دورانی‬ ‫سیستم‬
‫فوران‬ ‫کنترل‬ ‫سیستم‬
‫ها‬ ‫نشانگر‬ ‫و‬ ‫دقیق‬ ‫ابزار‬ ‫سیستم‬

(‫علوم‬ ‫وزارت‬ ‫مصوب‬1390( )‫ادامه‬)
‫رشته‬‫حفاری‬ ‫های‬
‫وظایف‬
‫لوله‬‫آنها‬ ‫مشخصات‬ ‫و‬ ‫حفاری‬ ‫های‬
‫لوله‬‫آنها‬ ‫مشخصات‬ ‫و‬ ‫وزنه‬ ‫های‬
‫طراحی‬ ‫به‬ ‫مربوط‬ ‫محاسبات‬
‫حفاری‬ ‫رشته‬ ‫یک‬:
‫شناوری‬ ‫ضریب‬
‫رش‬ ‫امتداد‬ ‫در‬ ‫تنش‬ ‫توزیع‬ ‫محاسبه‬‫ته‬
‫لوله‬ ‫از‬ ‫الزم‬ ‫طول‬ ‫محاسبه‬‫وزنه‬ ‫های‬
‫خنثی‬ ‫نقطه‬
‫طول‬ ‫حداکثر‬ ‫تعیین‬
‫لوله‬‫لوله‬ ‫گرید‬ ‫هر‬ ‫از‬ ‫حفاری‬ ‫های‬
‫مجاز‬ ‫کشش‬ ‫میزان‬ ‫حداکثر‬ ‫تعیین‬
‫ها‬ ‫لوله‬ ‫گیر‬ ‫هنگام‬ ‫در‬
‫حفاری‬ ‫رشته‬ ‫دیگر‬ ‫اجزاء‬:
،‫زنها‬ ‫ضربه‬
،‫ها‬ ‫کننده‬ ‫پایدار‬
،‫ریمرها‬
‫و‬ ‫چاهی‬ ‫درون‬ ‫موتورهای‬ ‫با‬ ‫آشنایی‬
‫ها‬ ‫توربین‬

(‫علوم‬ ‫وزارت‬ ‫مصوب‬1390( )‫ادامه‬)
‫مته‬ ‫تکنولوژی‬‫حفاری‬ ‫های‬
‫مته‬ ‫انواع‬‫و‬ ‫کاجه‬ ‫سه‬ ‫های‬Drag
Bit‫یک‬ ‫هر‬ ‫کندن‬ ‫مکانیزم‬ ‫و‬
‫مته‬ ‫داخلی‬ ‫ساختمان‬‫سه‬ ‫های‬
‫کاجه‬
‫قاب‬ ‫حسب‬ ‫بر‬ ‫سازند‬ ‫بندی‬ ‫طبقه‬‫لیت‬
‫حفاری‬
‫حفاری‬ ‫سرعت‬ ‫بر‬ ‫موثر‬ ‫عوامل‬
‫مته‬ ‫فرسایش‬ ‫بر‬ ‫موثر‬ ‫عوامل‬
‫مته‬ ‫بندی‬ ‫طبقه‬‫اساس‬ ‫بر‬ ‫ها‬
‫استاندارد‬IADC
‫مته‬ ‫ارزیابی‬‫ها‬
‫مته‬‫و‬ ‫الماسه‬ ‫های‬PDC
‫حفاری‬ ‫سیاالت‬ ‫بر‬ ‫ای‬ ‫مقدمه‬:
‫وظایف‬
‫بندی‬ ‫طبقه‬
‫افزایه‬‫اصلی‬ ‫های‬
‫نیوتنی‬ ‫غیر‬ ‫و‬ ‫نیوتنی‬ ‫سیاالت‬
‫هیدرولیک‬ ‫اهداف‬

Extra (Beyond scope)
Simulating experiments using relevant software

‫حفاری‬ ‫مهندسی‬ ‫درس‬ ‫پیشنهادی‬ ‫منابع‬(1)
(‫علوم‬ ‫وزارت‬ ‫مصوب‬1390)
K.K. Millheim - M. E. Chenevert - F.S. Young Jr.:
Applied Drilling Engineering

Texts and Materials:
Jorge H.B. Sampaio Jr.
“Drilling Engineering Fundamentals.”
(Q931+DE1+L00) Lecture notes from class
These materials may include
handouts provided in class.
computer files available on the course weblog
…

Class Lectures

Major References
(WEC) Rabia, Hussain.
Well Engineering &
Construction.
Entrac Consulting
Limited, 2002.
Chapters:
10 Drillstring Design,
16 Rig Components,
17 Well Costing

Major References
(CDF) Jorge H.B. Sampaio
Jr. “Drilling Engineering
Fundamentals.” Master
of Petroleum
Engineering. Curtin
University of Technology,
2007.
Chapters:
1 Introduction,
2 Rotary Drilling System,
3 Drillstring Tubulars and
Equipment,
4 Introduction to
Hydraulics,
5 Drillstring Design

Side References
Bourgoyne Jr, Adam T.,
et al. "Drilling
hydraulics." Applied
Drilling Engineering
Textbook (1986): 1-8.
Chapters:
1 (Rotary Drilling), 2
(Drilling Fluids), 4
(Drilling Hydraulics) and
5 (Rotary Drilling Bits)

‫فارسی‬ ‫منابع‬(‫کمکی‬)
‫کتاب‬ ‫نام‬:‫حفاری‬ ‫مهندسی‬
‫کاربردی‬
‫نویسنده‬ ‫نام‬:‫آدام‬ ،‫نادری‬ ‫محمد‬
‫تی‬.‫آر‬ ‫جی‬ ‫بورگوین‬.‫کی‬ ‫کیت‬ ،.
‫ای‬ ‫مارتین‬ ،‫میلهم‬.،‫چنورت‬
‫مترجمان‬:‫مرتضی‬ ،‫سجادیان‬ ‫احمد‬
‫امید‬ ‫سید‬ ،‫کوجان‬‫پور‬ ‫ابراهیم‬
‫امیر‬ ،‫دیوکالهی‬ ‫حمیدیان‬
‫دهلر‬‫طاهری‬
‫اول‬ ‫چاپ‬1388
‫ناشر‬:‫دانش‬ ‫مشتاق‬(‫انتشارات‬)
‫اول‬ ‫جلد‬( :‫چهار‬ ‫تا‬ ‫یک‬ ‫فصول‬)

Class Schedule (Beta)
Lec. 1
 Introduction
Lec. 2
Lec. 3
Lec. 4
Lec. 5
Lec. 6

Lec. 7
Lec. 8
Lec. 9
Lec. 10

Details (Beta)
Date Lecture Topic Reading Assignment (prior to class)
01
02
03

Communication Methods
Preferred methods
Break time and mid class
First Point of Contact via
email (Limited)
Will be answered with
some delay
(an hour to a week
according to importance
and requirements)
Mention your personal
and educational info in
emails (Name, Student #,
Course title, Subject)
Avoid following
communication methods
Appointments
Phone calls
Short Message Service
(SMS)
Instant message (IM)
chats

Frequently Asked Questions (FAQ)
Class schedule:
Almost all sessions will
be held
Preferred topics:
Course related
Research study
Paper for International
conferences
Articles for national
journals
Avoided helps:
Other courses
Sources, exams, exercises,
class works and so on
B.Sc. Thesis
Aside supervised ones
M.Sc. Conquer
Trainee
Private class
Educational problems
Personal problems
National conference
paper

1. Introduction
2. Types of rigs
3. Personnel at Rig Site
4. How to drill a well

2 drilling goals
to build the well according to its purpose and in a
safe manner
(i.e, avoiding personal injuries
and avoiding technical problems)
to complete it with minimum cost
Thereto the overall costs of the well during its lifetime in
conjunction with the field development aspects shall be
minimized.

Parameters
The overall cost minimization, or optimization, may
influence
the location from where the well is drilled,
(e.g., an extended reach onshore or above reservoir offshore),
the drilling technology applied,
(e.g., conventional or slim–hole drilling, overbalanced or
underbalanced, vertical or horizontal, etc),
and which evaluation procedures are run to gather
subsurface information to optimize future wells.

drilling technologies
To build a hole,
different drilling
technologies have been
invented:
Percussion drilling
Cable drilling
“Pennsylvanian drilling”
Drillstring
• With mud Quick
percussion drilling
• Without mud
“Canadian drilling”
Rotating drilling (Will be
discussed exclusively)
Full cross-section drilling
• Surface driven
o Rotary bit
o Rotary nozzle
• Subsurface driven
o Turbine drilling
o Positive
displacement
motor drilling
o Electro motor
drilling
Annular drilling
• Diamond coring
• Shot drilling

drilling technologies (Cont.)
Special techniques
Abrasive jet drilling
Cavitating jet drilling
Electric arc and plasma
drilling
Electric beam drilling
Electric disintegration
drilling
Explosive drilling
Flame jet drilling
Implosion drilling
Laser drilling
REAM drilling
Replaceable cutterhead
drilling
Rocket exhaust drilling
Spark drilling
Subterrene drilling
Terra drilling
Thermal-mechanical
drilling
Thermocorer drilling

drilling rig
A drilling rig is a device used to drill,
case and cement oil and gas wells.
The correct procedure for selecting and sizing a
drilling rig is as follows:
Design the well
Establish the various loads to be expected during drilling
and testing operations and use the highest loads. This
point establishes the DEPTH RATING OF THE RIG.
Compare the rating of existing rigs with the design loads
Select the appropriate rig and its components.

Rig Classification
Rotary
Drilling Rigs
Land
Mobile
Jackknife
Portable
Mast
Conventional
Marine
Bottom
Supported
Platform
Self
Contained
Tendered
Barge
Jack-Up Submersible
Floating
Drill Ship
Semi
Submersible
Caisson
Vessel
Tension Leg

Land: Mobile Rigs
Jackknife rig Portable mast

Marine:
Bottom Supported Platform rigs
Self Contained Tendered

Marine:
Other Bottom Supported rigs
A Jack–Up rig A submersible platform
A cantilever rig on a barge

Marine: Floating rigs
Caisson vessel
(also called
sparbuoy) and
Diagram of a
spar–buoy
A tension–
leg platform
A drill–ship Semi–
submersible
vessel

comparison of drilling rigs

Well Classifications
According to a wells final depth, it can be classified
into:
Shallow well: < 2000m
Conventional well: 2 000m – 3500m
Deep well: 3500m – 5000m
Ultra deep well: > 5 000m
With the help of advanced technologies in
MWD/LWD and extended reach drilling techniques,
horizontal departures of more than10000m are
possible today.

Personnel
People directly involved in drilling a well are
employed either by
the operating company,
the drilling contractor,
or one of the service and supply companies
The operating company is the owner of the
lease/block and principal user of the services
provided by the drilling contractor and the different
service companies.

Tasks
Since drilling contractors are companies that
perform the actual drilling of the well, their main
job is to drill a hole to the depth/location and
specifications set by the operator.
Along with hiring a drilling contractor, the operator
usually employs various service and supply
companies to perform
logging,
cementing,
or any other special operations, including maintaining
the drilling fluid in its planed condition.

drilling crews
Most drilling crews consist of
a tool pusher,
a driller,
a derrickman,
a mud logger,
and two or three rotary helpers
(also called floormen or roughnecks).
Along with this basic crew configuration the
operator sends usually a representative, called
company man to the rig.
For offshore operations the crews usually consist of
many more employees.

crew requirements
Tool Pusher:
supervises all drilling operations and is the leading man
of the drilling contractor on location.
Company Man:
The company man is in direct charge of all company’s
activities on the rig site.
He is responsible for the drilling strategy as well as the
supplies and services in need. His decisions directly
effect the progress of the well.

crew requirements (Cont.)
Driller:
The driller operates the drilling
machinery on the rig floor and is the
overall supervisor of all floormen.
He reports directly to the tool
pusher and is the person who is
most closely involved in the drilling
process.
He operates, from his position at the
control console, the rig floor brakes,
switches, levers, and all other
related controls that influence the
drilling parameters.
In case of a kick he is the first person
to take action by moving the bit off
bottom and closing the BOP.

Inside a control console

Derrick Man:
The derrickman works on the so–
called monkeyboard, a small
platform up in the derrick,
usually about 90 ft above the
rotary table.
When a connection is made or
during tripping operations he is
handling and guiding the upper end
of the pipe.
During drilling operations the
derrickman is responsible for
maintaining and repairing the
pumps and other equipment as
well as keeping tabs on the drilling
fluid.

Floormen:
During tripping, the rotary helpers are
responsible for handling the lower end
of the drill pipe as well as operating
tongs and wrenches to make or break
up a connection.
During other times, they also maintain
equipment, keep it clean, do painting
and in general help where ever help is
needed.
Mud Engineer, Mud Logger:
The service company who provides the
mud almost always sends a mud
engineer and a mud logger to the rig
site. They are constantly responsible for
logging what is happening in the hole as
well as maintaining the proper mud
conditions.

drilling process
In rotary drilling, the rock is destroyed by the action
of rotation and axial force applied to a drilling bit.
The drilling bit is located at the end of a drill string
which is composed of drill pipes (also called joints
or singles), drill collars, and other specialized drilling
tools.
Drill collars are thick walled tubes responsible for
applying the axial force at the bit.
Rotation at the bit is usually obtained by rotating the
whole drill string from the surface.

A simplified drillstring
The components of the
drillstring are:
Drillpipe
Drillcollars
Other Accessories called bottom
hole assembly (BHA) including:
Heavy-walled drillpipe (HWDP)
Stabilisers
Reamers
Directional control equipment
Etc.

Functions of the drillstring
The drill string is the mechanical linkage connecting
the drillbit at the bottom of the hole
to the rotary drive system on the surface.
The drillstring serves the following functions:
transmits rotation to the drillbit
exerts weight on the bit;
the compressive force necessary to break the rock
guides and controls the trajectory of the bit; and
allows fluid circulation
which is required for cooling the bit and for cleaning the hole.

drilling process (Cont.)
A large variety of bit models and designs are available in
industry.
The choice of the right bit,
based on the characteristics of the formations to be drilled,
and the right parameters (weight on bit and rotary speed)
are the two most basic problems the drilling engineer faces
during drilling planning and drilling operation.
The cuttings are lifted to the surface by the drilling fluid.
At the surface, the cuttings are separated from the drilling
fluid by several solid removal equipment.
Drilling mud is picked up by the system of pumps and
pumped again down the hole.

connection
As drilling
progresses, new
joints are added
to the top of the
drill string
increasing its
length, in an
operation called
connection.
A pipe slips is
used to transfer
the weight of
the drillstring
from the hook to
the master
bushing.

round trip
As the bit gets dull, a round trip is performed to
bring the dull bit to the surface and replace it by a
new one.
A round trip is performed also to change the BHA.
The drillstring is also removed to run a casing
string. The operation is done by removing stands of
two (“doubles”), three (“thribbles”) or even four
(“fourbles”) joints connected, and stacking them
upright in the rig.

Removing one stand of drillstring

wiper trip
Sometimes the drillstring is not completely run out
of the hole.
It is just lifted up to the top of the open-hole
section and then lowered back again while
continuously circulating with drilling mud.
Such a trip, called wiper trip,
is carried out to clean the hole from remaining cuttings
that may have settled along the open–hole section.

1. (CDF) Jorge H.B. Sampaio Jr. “Drilling
Engineering Fundamentals.” Master of
Petroleum Engineering. Curtin University of
Technology, 2007. Chapter 1 and 2
2. (WEC) Rabia, Hussain. Well Engineering &
Construction. Entrac Consulting Limited, 2002.
Chapter 16

1. time estimates
A. Example of time-depth curve
2. Elements Of Well Costing
3. Risk Assessment In Drilling Cost Calculations
4. Drilling Contracting Strategies

Authorization For Expenditure
elements which comprise the well cost:
rig, casing, people, drilling equipment etc.
The final sheet summarizing the well cost is usually
described as the AFE: “Authorization For Expenditure”.
The AFE is the budget for the well.
Once the AFE is prepared, it should then be approved and
signed by a senior manager from the operator.
The AFE sheet would also contain:
project description, summary and phasing of expenditure,
partners shares and well cost breakdown.
Details of the well will be attached to the AFE sheet as a form
of technical justification.

FACTORS AFFECTING WELL COST
Well costs for a single
well depend on:
Geographical location:
land or offshore, country
Type of well:
exploration or
development,
HPHT or
sour gas well
Drillability
Hole depth
Well target(s)
Profile
vertical/ horizontal/
multilateral
Subsurface problems
Rig costs:
land rig, jack-up,
semi-submersible or
drillship and rating of rig
Completion type
Knowledge of the area:
wildcat, exploration or
development

time spent on a well
The time spent on a well consists of:
Drilling times spent on making hole, including
circulation, wiper trips and tripping, directional work,
geological sidetrack and hole opening.
Flat times spent on running and cementing casing,
making up BOPS and wellheads.
Testing and completion time.
Formation evaluation time including coring, logging etc.
Rig up and rig down of rig.
Non-productive time.

time required to drill the well
Before an AFE can be prepared,
an accurate “estimate” of the time required
to drill the well must be prepared.
The time estimate should consider:
ROP in offset wells.
From this the total drilling time for each section
may be determined.
Flat times for running and cementing casing
Flat times for nippling up/down BOPs and nippling up
wellheads
Circulation times.
BHA make up times.

DETAILED TIME ESTIMATE
Detailed time estimates can be prepared for each
hole section by considering the individual
operations involved.
This exercise requires experience on part of the engineer
and also detailed knowledge of previous drilling
experience in the area.

Detailed time estimate for
30” conductor

Calculation of
time -depth curve
Assume the following well design for Well Pak-1:
36” Hole / 30" Conductor 50 m BRT (below rotary table)
26” Hole / 20" Casing 595 m BRT
17.5”Hole / 13.375" Casing 1421 m BRT
12.25” / 9.625" Casing 2334 m BRT
8.5” Hole / 7" Casing 3620 m BRT
Total Depth 3620 m BRT
From three offset wells, the following data was
established for average ROP for each hole section:
36” Hole 5.5 m/hr
26” Hole 5.5 m/hr
17.5”Hole 7.9 m/hr
12.25” 4.6 m/hr
8.5” Hole 2.5 m/hr

Calculation of
time -depth curve (Cont.)
The expected flat times for this well are :
Calculate the total drilling time and
plot the depth-time curve.

Calculations of
planned drilling times
Solution:
Example 17.1: Calculation of time -depth curve,
WEC PGO: 752

Time-depth calculations

Time-depth curve

ELEMENTS OF WELL COSTING
There are three main
elements of the well
cost.
No matter what service
or product is used, it will
fall under one of the
following three cost
elements, namely:
Rig costs
Tangibles
Services
For offshore wells
there are other costs
which must be included:
Supply boats
Stand-by boats
Helicopters

RIG COSTS
As the name implies,
rig costs refer to the cost
of hiring the drilling rig
and its associated
equipment.
This cost can be up to
70% of well cost,
especially for
semi-submersible rigs
or drilling ships.
Rig cost depends entirely
on the rig rate per day,
usually expressed as
$/day.
Rig rate depends on:
Type of rig
Market conditions
Length of contract
Days on well
Mobilization/
Demobilization of rig and
equipment
Supervision
Additional rig charges

TANGIBLES
Tangibles refer to
the products
used on the well.
These include:
Casing
For an example:
length of casing and
selecting the appropriate
casing grades/weights for
each hole section
Tubing/
completion equipment
Wellhead/accessories
Bits
Coreheads
Cement products
Mud products
Solids control
consumables
Fuel and lubes
Other materials and
supplies

SERVICES
This group of costs refers
to any service required on
the well. Services include:
Communications
Rig positioning
usually required in offshore
operations
Logging (wireline)
both open & cased hole
logs
MWD/ LWD
Downhole Motors
Solids Control Equipment
Mud Engineering
Directional Engineering
Surveying
determination of
hole angle and azimuth.
includes the cost of single
shots, magnetic multi-shots
(MMS) and gyros
Cementing
Mud Logging
Fishing
only included if experience
in the area dictates that
fishing may be required in
some parts of the hole
Downhole tools
including jars, shock subs
Casing services

NON PRODUCTIVE TIME (NPT)
The time required for any routine or abnormal
operation which is carried out as a result of a failure
is defined as Non Productive Time (NPT)
Non-Productive Time (NPT) in drilling operations
currently account for 20% of total drilling time.
the NPT is calculated as the time
from when the problem occurred to the time when
operations are back to prior to the problem occurring.
The NPT time includes normal operations
such as POH, RIH, circulating etc.
standby time
Waiting on weather or waiting on orders, people or
equipment is not NPT. This is standby time.

CLASSIFICATION OF NPT
Rig equipment
(Down time due to: Mud
pumps, generators, shakers,
rotary table, top drive/Kelly,
hoist, drilling line, gauges,
compressors and anchors.
Note that within the rig
contract a fixed time is
allowed for rig repairs/
maintenance. The NPT rig
time should be the time
recorded above the agreed
fixed repair time).
Surface Equipment
Downhole Equipment
Drillstring Equipment
Logging equipment
Stuckpipe and Fishing of
BHA equipment
Casing Hardware and
Cementing Equipment
Fluids
Hole problems
Well Control
Testing and Completion
NPT

two major elements of
well cost estimates
it is essential that cost
estimates are made
realistic, as low as
possible and produced in
a consistent manner.
These criteria are
achieved through the
application of risk
assessment.
Well cost estimates are
made up of two major
elements:
Time dependent costs
Rig costs and services are
greatly impacted by the
time estimate.
Tangible costs
Tangible costs can be
estimated at the
budgetary stage (before a
detailed well plan is
made) or at the AFE stage
after the detailed well
plan is made.
The risk involved in
estimating tangibles is
usually small.

levels of risks
Risk assessment is defined in terms of the
probability of meeting a given target. There are
three levels of risks:
P10 (only a 10% chance of being achieved)
This is a highly optimistic estimate which can only be
achieved under exceptional circumstances.
As there is no exact method for estimating P10, it is now
customary to base P10 value on the best possible
performance on any operation on any well in the area.
the total P10 value for a given section will be the best
individual values from several wells for all operations
required to drill, case and cement the given hole section.

levels of risks (Cont.)
P50
This is the key figure in most well cost estimates.
This estimate will be based on known information
derived from offset data.
P90
This is an estimate of well cost which is likely to be met
90% of the time and that well costs can not be exceeded
except under exceptional cases.
This estimate was widely used in the oil industry before
accurate cost estimating was introduced in the early 1990’s.

COST REDUCTION
There are two elements of costs which must be
controlled:
Capital Expenditure (Capex):
This includes the cost of finding and developing an
oil/gas field.
The cost of drilling operations is the major cost element
and must be kept to an acceptable value.
Operating Cost (OPEX):
This includes the actual cost of production: cost of
maintaining the platform, wells, pipelines etc.
We will not be concerned with these costs as they are
part of production operations.

Price of oil production
judging a minimum
price per barrel of oil (2002):
In the North Sea, it is accepted
that the principle of 1/3/3
results in a profitable
operation.
 $1 for finding,
$3 for developing and
$3 for production.
 combined cost of $7 per barrel
In the Middle East, this
combined cost can be as low
as $2 for some giant fields.
In general the more remote
the area the more expensive
is the final cost of barrel of
oil.
This is particularly true for
deep waters in hostile
environments.
The following is a list of
measures to reduce costs:
Technical innovation
Productivity improvement:
e.g. faster drilling operations
Increased operational
effectiveness
Incentive contracts
(sharing gains and pains)
Less people

types of contracts
There are basically four types of contracts which are
currently used in the oil industry:
Conventional
Integrated Services (IS)
Integrated Project Management (IPM)
Turn Key
The type of drilling contract used can mean the
difference between an efficient and a less efficient
operation.
Indeed, going for one type, say turn key, can mean that the
operator has no control over the operation whatsoever and
has no means of building knowledge for future operations.

CONVENTIONAL CONTRACT
In this type of contract, the E&P company does every thing using
its own staff or contractors. This is the most involved type of
contract and can mean handling up to 100 contracts per well.
 the operator has total control over the operation and carries full risk.
 The contractor has no risk and it could be argued that
 the contractor has no incentive in speeding up the operation.
This type of contract has the advantage that
 lessons learnt during drilling operations are kept within the company
and used to improve future operations.
Nowadays, only large operators opt for this type of contract.
A variation of the above contract is to include an incentive clause
for completing operations early or if a certain depth is reached
within an agreed time scale.
 The contractor will be paid a certain percentage of the savings made if
operations are completed ahead of the planned agreed drilling time.

INTEGRATED SERVICES (IS)
In this type of contract, major services are
integrated under two or three main contracts.
These contracts are then given to lead contractors who,
in turn, would subcontract all or parts of the contract to
other subcontractor.
The lead contractor hold total responsibility for his
contract and is free to choose its subcontractors.
The operator still holds major contracts such as rig,
wellheads and casing.
Also the operator appoints one of its staff to act as a
coordinator for the drilling operation.

INTEGRATED PROJECT MANAGEMENT
(IPM)
In this type of contract, a main contractor is chosen.
This contractor is the Integrated Project Management (IPM)
contractor.
The contractor is responsible for 20-30 service companies.
• Service companies may be responsible for other service companies.
The drilling operation will be controlled by a
representative from the IPM contractor.
The operator may hold one or two major contracts.
It is one of the worst kind of contracts for the operator
because:
There is virtually no learning for the operator.
The incentive contract is built on a time-depth curve
developed and based on the contractor’s experience. Use of
better equipment and personnel may beat the IPM
contractor’s time-curve.

TURN KEY CONTRACT
This is the easiest of all the above contracts.
The operator chooses a contractor.
The contractors submits a lump sum for drilling a well:
• from spud to finish with operator virtually not involved.
The contractor carries all risks if the well comes behind time
and also gains all benefits if he should drill the well faster.
Contractors only opt for this type of contract
if they know the area extremely well or
during times of reduced activities.
The operator opts for this type of contract
if he has a limited budget or
has no knowledge of drilling in the area.

CURRENT AND FUTURE TRENDS IN
DRILLING CONTRACTS
There are two new development in drilling and
production contracts:
Production Sharing Agreement
It stipulates that the contractor will be paid
a certain percentage of the produced fluids (oil or gas) in return
for the services of the contractor in drilling and producing the
wells.
• The agreement may be time-dependent running for a fixed
number of years or
may include an initial payment for the contractor
in addition to a percentage of the production.

CURRENT AND FUTURE TRENDS IN
DRILLING CONTRACTS (Cont.)
Capital Return Agreement Plus Agreed Production
It stipulates that the contractor will develop a field using his
own finance. In return, the operator (or national oil company)
will pay the contractor all his capital expenditure plus an agreed
percentage of the production.
• In Iran where this type of contract is used, the agreed production
is limited to a fixed number of years. The ownership of the field
and its facilities always remain with the operator.
These new types of contracts were initially initiated
in some Middle Eastern countries attempting to
draw western investment.
These contracts are still developing in nature and have
now been used by a number of third world countries.

Chapter 17

1. Rotary Drilling Systems
2. Power System
A. equipment
B. calculations

rig systems
For all rigs, the depth of
the planned well
determines basic rig
requirements. The most
important rig systems
are:
Power system,
Hoisting system,
Drilling fluid circulation
system,
Rotary system,
Derrick and substructure,
Well control system,
Well monitoring system

Typical rig components

power supply
The power system of a rotary drilling rig has to
supply power to all the other systems.
the system must provide power for
pumps in general, rig light, air compressors, etc.
Since the largest power consumers on a rotary
drilling rig are
the hoisting, the circulation system, and the rotary
system,
these components determine mainly the total power
requirements.

Power consumption
The actual power required will depend on
the drilling job being carried out.
During typical drilling operations,
the hoisting and the rotary systems are not
operated at the same time.
Therefore the same engines
can be used to perform both functions.
The maximum power used
is during hoisting and circulation.
The least power used
is during wireline operations.

power system
Drilling rig power systems are classified
as direct drive type (internal combustion engines supply
mechanical power to the rig )
and electric type.
In both cases,
the sources of energy are diesel fueled engines.
Most rigs use
1 to 3 engines to power the drawworks and rotary table.
The engines are usually rated between 400 and 800 hp.
As guideline, power requirements
for most onshore rigs are between 1,000 to 3,000 hp.
Offshore rigs in general use much more power.

Sample of a land rig power supply

SCR Unit
The power on modern rigs is most
commonly generated by
diesel-electric power units.
The power produced is AC current
which is then converted to DC
current by the use of SCR
(Silicon Controlled Rectifier).
The current is delivered by cables
to electric motors attached directly
to the equipment involved such as
mud pumps,
rotary table, Drawworks etc.

power system performance
The performance of a
rig power system is
characterized by
the output horsepower,
torque,
and fuel consumption
for various engine
speeds.
These three
parameters are related
by the efficiency of
each system.

energy consumption by the engines
Heating
values of fuels
The energy consumed by the engines comes
from burning fuels.
The engine transforms the chemical energy
of the fuel into work.
 No engine can transform totally the chemical
energy into work.
 Most of the energy that enters the engine is
lost as heat.
The thermal efficiency Et of a machine is
defined as the ratio of the work W
generated to the chemical energy consumed
to perform this calculation, we must use the
same units both to the work and to the
chemical energy.
 1 BTU = 778.17 lbf*ft,
Fuel Type
Heating
Value
(BTU/lbm)
Density
(lbm/gal)
Diesel 19000 7.2
Gasoline 20000 6.6
Butane
(liquid)
21000 4.7
Methane
(gas)
24000 –

thermal efficiency
Engines are normally rated by the power P
they can deliver at a given working regime.
Power if defined as the rate work is performed,
that is work per unit of time.
If ˙Q is the rate of chemical energy consumed by the machine
(chemical energy per unit of time),
we can rewrite the expression for the thermal efficiency as:
To calculate ˙Q we need to know the type of fuel and
the rate of fuel consumption in mass per unit time.
Consumption of gaseous fuels is given in mass per unit time.
consumption for liquid fuels is given in volume per unit time.
we need to know the density of the fluid.

output power
A system produces mechanical work when the sole
result of the process could be the raising of a weight
(most time limited by its efficiency).
P is power, and v the velocity (assuming F constant).
When a rotating machine is operating (for example,
an internal combustion engine or an electrical motor),
we cannot measure its power,
but we can measure its rotating speed (normally in RPM) and
the torque at the shaft.
This is normally performed in a machine called dynamometer.

output power
The expression relating power to angular velocity
and torque is:
ω is the angular velocity (in radians per unit of time)
T is the torque.
A common unit of power is the hp (horse power).
One hp is the power required
to raise a weight of 33,000 lbf by one foot in one minute:

output power
For T in ft lbf and N in RPM we have:
that is

mechanical horsepower Correction
When the rig is operated
at environments with non–standard temperatures
(85F=29C) or
at high altitudes,
the mechanical horsepower requirements
have to be corrected.
The correction should follow
the American Petroleum Institute (API) standard 7B-llC:
Deduction of 3% of the standard brake horsepower for each
1000 ft of altitude above mean sea level.
Deduction of 1% of the standard brake horsepower for each
10F rise or fall in temperature above or below 85F.

Calculation of the output
power and the overall
efficiency
A diesel engine gives
an output torque of 1740 ft lbf
at an engine speed of 1200 RPM.
 If the fuel consumption rate was 31.5 gal/hr,
what is the output power and
the overall efficiency of the engine?

the output power and
the overall efficiency
The power delivered at the given regime is:
Diesel is consumed at 31.5 gal/hr. From Table we have:
Converting to hp, results in:
The thermal efficiency is:

Technology, 2007. Chapter 2
Chapter 16

1. Hoisting System:
A. Introduction
B. The Block & Tackle
a. Mechanical advantage and Efficiency
b. Hook Power
C. Load Applied to the Derrick

Typical hoisting system
The hoisting system is used
to raise, lower, and suspend
equipment in the well
(e.g., drillstring, casing, etc).
It is consists of:
derrick (not shown)
draw works
the block-tackle system
 fast line (braided steel cable)
 crown block
 traveling block
 dead line (1” to 13/4=3.25”)
 deal line anchor,
 storage reel,
 hook.

The Derrick
The derrick provides
the necessary height and
support to lift loads in and out of the well.
The derrick must be strong enough to support
the hook load, deadline and fastline loads,
pipe setback load and wind loads.
Derricks are rated by the API according
to their height (to handle 2, 3, or 4 joints) and
their ability to withstand wind and compressive loads.

The Derrick
The derrick stands
above the derrick floor.
It is the stage where several surface
drilling operations occur.
At the derrick floor are located
the drawworks, the driller’s console,
the driller’s house (or “doghouse”),
the rotary table, the drilling fluid
manifold, and several other tools to
operate the drillstring.
The space below the derrick floor is
the substructure.
The height of the substructure should
be enough to accommodate the
wellhead and BOPs.
doghouse

Substructure and Monkey Board
At about 3/4 of the height of
the derrick is located a platform
called “monkey board”.
This platform is used to operate
the drillstring stands during trip
operations.
During drillstring trips, the stands
are kept stood in in the mast, held
by “fingers” in the derrick rack near
the monkey board.

drawworks
The drawworks provides
hoisting and
braking power
required
to handle the heavy
equipment in the borehole.
It is composed of
a wire rope drum,
mechanical and
hydraulic brakes,
the transmission,
and the cathead
 (small winches operated by
hand or remotely to provide
hoisting and pulling power to
operate small loads and
tools in the derrick area).
a typical onshore rig drawworks

Reeling in and out
The reeling–in of the drilling line
is powered by an electric motor or Diesel engine
the reeling–out
is powered by gravity
To control the reeling out,
mechanical brakes and
auxiliary hydraulic or magnetic brakes
are used, which dissipates the energy required to reduce
the speed and/or stop the downward movement of the
suspended equipment.

The Block & Tackle
Fast line
The drilling line coming from the drawworks, called fast line, goes
over a pulley system mounted at the top of the derrick,
 called the crown block,
and down to another pulley system
 called the traveling block.
block-tackle
The assembly of crown block, traveling block and drilling line
The number of lines n of a tackle
is twice the number of (active) pulleys in the traveling block.
The last line of the tackle
is called dead line
and is anchored to the derrick floor, close to one of its legs.
Below and connected to the traveling block is a hook to
which drilling equipment can be hung.

block-tackle system calculations
The block-tackle system
provides a mechanical advantage to the drawworks, and
reduces the total load applied to the derrick.
We will be interested in calculating
the fast line force Ff (provided by the drawworks)
required to raise a weight W in the hook, and
the total load applied to the rig and
its distribution on the derrick floor.

Forces acting in the block–tackle

Dead Line Anchor
This allows new lengths of
line to be fed into the
system to replace the worn
parts of the line that have
been moving on the pulleys
of the crown block or the
travelling block.
The worn parts are
regularly cut and removed
by a process called: Slip and
Cut Practice.
Slipping the line,
then cutting it off helps to
increase the lifetime of the
drilling line.

Drilling Line
The drilling is basically a wire
rope made up of strands
wound around a steel core.
 Each strand contains a number
of small wires wound around a
central core.
The drilling line is of the round
strand type with Lang’s lay.
The drilling line has a 6x19
construction with
Independent Wire Rope Core
(IWRC).
 6 strands and each strand
containing 19 filler wires.
The size of the drilling line
varies from ½ "to 2 ".

Ideal Mechanical advantage
The mechanical advantage AM of the block–tackle
is defined as the ratio of the load W in the hook
to the tensile force on the fast line Ff :
For an ideal, frictionless system,
the tension in the drilling line
is the same throughout the system, so that W = n Ff .
Therefore, the ideal mechanical advantage is equal to
the number of lines strung through the traveling block:

efficiency of a real pulley
Friction between the wire rope and sheaves reduce
the efficiency of the hoisting system.
In a real pulley, however, the tensile forces
in the cable or rope in a pulley are not identical.
If Fi and Fo are the input and output tensile forces of
the rope in the pulley,
the efficiency of a real pulley is:
We will assume that all pulleys in the hoisting system
have the same efficiency, and we want to
calculate the mechanical advantage of a real pulley system.

Efficiency Of The Hoisting Systems
(Hoisting Operations)
during hoisting (pulling out of hole) operations
If Ff is the force in the fast line,
the force F1 in the line over the first pulley
(in the crown block) is
The force in the line over the second pulley
(in the traveling block) is
Using the same reasoning over and over,
the force in the ith line is
The total load W acting in the hook is equal to
the sum of the forces in each line of the traveling block.

Calculation of fast line load during
hoisting
AM=the real mechanical advantage
The overall efficiency E of the system
of pulleys is defined as the ratio of
the real mechanical advantage to the
ideal mechanical advantage
A typical value for the efficiency of
ball–bearing pulleys is = 0.96.
Table shows the calculated and
industry average overall efficiency for
the usual number of lines.
if E is known, the fast line force Ff
required to rise a load W can be
calculated

Calculations of minor loads
Using the same reasoning Deadline-load is given by:
𝐹𝑑 = 𝐹𝑓 ∗ 𝜂 𝑛 =
𝑊∗𝜂 𝑛
𝑛∗𝐸
If the breaking strength of the drilling line is known,
then a design factor, DF, may be calculated as follows:
𝐷𝐹 =
𝑛𝑜𝑚𝑖𝑛𝑎𝑙 𝑠𝑡𝑟𝑒𝑛𝑔𝑡ℎ 𝑜𝑓 𝑤𝑖𝑟𝑒 𝑟𝑜𝑝𝑒 𝑙𝑏
𝑓𝑎𝑠𝑡 𝑙𝑖𝑛𝑒 𝑙𝑜𝑎𝑑 𝑙𝑏
Lowering Operations:
During lowering of pipe,
the efficiency factor is: 𝐸𝑙𝑜𝑤𝑒𝑟𝑖𝑛𝑔 =
𝜂∗𝜂 𝑛 1−𝜂
1−𝜂 𝑛
And fast-line load is: 𝐹 𝑓 𝑙𝑜𝑤𝑒𝑟𝑖𝑛𝑔 =
𝑊∗𝜂 𝑛 1−𝜂
1−𝜂 𝑛

POWER REQUIREMENTS OF THE
DRAWWORKS
As a rule of thumb,
the drawwork should have 1 HP
for every 10 ft to be drilled.
Hence for a 20,000 ft well,
the drawwork should have 2000 HP.
A more rigorous way of calculating the horse power
requirements is to carry out output power at drum:
𝑃d = Ff ∗ Vf =
W
nE
∗ n ∗ vb =
W∗Vb
E
In the Imperial system, power is quoted in horse-power and the
above equation becomes:𝐷𝑟𝑢𝑚 𝑜𝑢𝑡𝑝𝑢𝑡 =
W∗vb
E∗33000
The proof has mentioned in the following slides:

Input vs. output power
For an ideal block–tackle system,
the input power (provided by the drawworks)
is equal to the output or hook power
(available to move the borehole equipments).
In this case,
the power delivered by the drawworks is equal to
the force in the fast line Ff
times the velocity of the fast line vf , and
the power developed at the hook is equal to
the force in the hook W
times the velocity of the traveling block vb.
That is

relationship between the drawworks
power and the hook power
Since for the ideal case n Ff = W, so
that is, the velocity of the block is
n times slower than the velocity of the fast line, and
this is valid also for the real case.
For the real case, Ff=W/nE, and multiplying both
sides by vf we obtain
which represents the real relationship between the
power delivered by the drawworks and the power
available in the hook,
where E is the overall efficiency of the block–tackle system.

The Block & Tackle
A rig must hoist a load of 300,000 lbf.
The drawworks can provide a maximum input
power to the block–tackle system of as 500 hp.
Eight lines are strung between the crown block and
traveling block.
Calculate
(1) the tension in the fast line
when upward motion is impending,
(2) the maximum hook horsepower,
(3) the maximum hoisting speed.

The Block & Tackle
Using E = 0.841 (average efficiency for n = 8) we
have:

Hook Loads
The following data refer to a 2 in block line with 12 lines of extra
improved plough steel wire rope strung to the travelling block.
 hole depth = 12,000 ft
 drillpipe = 4.5 in OD/3.958 in ID, 13.75 lb/ft
 drill collars = 800 ft, 8 in/2,825 in, 150 lb/ft
 mud weight = 9 ppg
 line and sheave efficiency coefficient = 0.9615
Calculate:
 A: weight of drill string in air and in mud;
 B: hook load, assuming weight of travelling block and hook to be 20,500
lb;
 C: deadline and fast-line loads;
 D: dynamic crown load;
 E: wireline design factor during drilling if breaking strength of wire is
228,000 lb
 F: design factor when running 7 in casing of 29 lb/ft.

Hook Loads
Clues:
Example 16.2: Hook Loads, WEC PGO: 725
Weight of drillstring in air
=weight of drillpipe + weight of drill collars
Weight of drillstring in mud
=buoyancy factor x weight in air
Hook load= weight of string in mud
+ weight of travelling block, etc.
Dynamic crown load = Fd + Ff + W

HOISTING DESIGN CONSIDERATIONS
The procedure for carrying out hoisting design
calculations are as follows:
Determine the deepest hole to be drilled
Determine the worst drilling loads or casing loads
Use these values to select
the drilling line,
the derrick capacity and
in turn the derrick

The total load applied to the derrick
The total load applied to the derrick, FD is equal to
the load in the hook (Hook load)
plus the force acting in the dead line
plus the force acting in the fast line
for the force in the fast line
The worst scenario is that for the real case.
For the dead line, however,
the worst scenario (largest force) is that of ideal case.
Therefore, the total load applied to the derrick is:

static derrick loading (SDL) and
wind load
Static derrick loading (SDL)=
fast-line load (where the efficiency is assumed equal 1) +
hook load +
dead-line load
So
SDL=HL/n+HL+HL/n
The wind load is given by: 0.004 V2 (units: lb/ft2)
V is wind speed in miles/hour
The wind load in lb/ft2 result must be multiplied by the WIND
LOAD AREA which is given in API 4A for different derrick sizes
in order to obtain the wind load in lb.
For offshore operations in windy areas,
this load can be very significant.

Derrick floor plan
The total load FD,
however, is not evenly distributed
over all legs of the derrick.
In a conventional derrick,
the drawworks is usually located
between two of the legs
The dead line, however must be
anchored close to one of the
remaining two legs
The side of the derrick opposite to
the drawworks is called V–gate.
This area must be kept free to allow
pipe handling.
Therefore, the dead line cannot be
anchored between legs A and B

the load in each leg
From this configuration the load in each leg is:
Evidently, the less loaded leg is leg B.
We can determine under which conditions the load
in leg A is greater then the load in legs C and D:
Since the efficiency E is usually greater than 0.5,
leg A will be the most loaded leg,
very likely it will be the first to fail
in the event of an excessive load is applied to the hook.

The equivalent derrick load and
The derrick efficiency factor
If a derrick is designed to support a maximum nominal
load Lmax, each leg can support Lmax 4 .
Therefore, the maximum hook load that the derrick can
support is
The equivalent derrick load, FDE,
is defined as four times the load in the most loaded leg.
The equivalent derrick load
(which depends on the number of lines)
must be less than the nominal capacity of the derrick.
The derrick efficiency factor, ED
is defined as the ratio of the total load applied to the derrick
to the equivalent derrick load:

derrick load
A rig must hoist a load of 300,000 lbf.
Eight lines are strung between the crown block and
traveling block.
calculate
(1) the actual derrick load,
(2) the equivalent derrick load, and
(3) the derrick efficient factor.

derrick load
Solution:
Using E = 0.841 (average efficiency for n = 8) we have:
(1) The actual derrick load is given by
(2) The equivalent derrick load is given by
(3) The derrick efficiency factor is

TON-MILES OF A DRILLING LINE
The drilling line, like any other drilling equipment, does
work at any time it is involved in moving equipment in
or out of the hole.
The amount of work done varies depending the
operation involved.
This work causes the wireline to wear and if the line is not
replaced it will eventually break.
The reader should note that the drilling line can only contact a
maximum of 50% of the sheaves at any one time, but the
damage will be done on the contact area any way.
The amount of work done need to be calculated to
determine when to change the drilling line.

Evaluation Of Total Service And Cut-off
Practice
Portions of the drilling line on the crown and
travelling blocks sheaves and on the hoisting drum
carry the greatest amount of work and are
subjected to a great deal of wear and tear.
These parts must be cut and removed at regular times
other wise the drilling line will fail by fatigue.
The process is called "slip and cut practice".
The length of line to be cut is equal to
Length of drum laps =
number of laps x drum circumference

1. Drilling Fluid Circulation System
A. Introduction
B. Mud Pumps
a. Duplex PDP & Triplex PDP
C. Solids removal
D. Solid Control Equipment
a. Shale shakers
b. Degasser
c. Mud Cleaners
E. Treatment and Mixing Equipment

drilling fluid roles
The drilling fluid plays several functions
in the drilling process.
The most important are:
clean the rock fragments from beneath the bit and
carry them to surface,
exert sufficient hydrostatic pressure
against the formation
to prevent formation fluids from flowing into the well,
maintain stability of the borehole walls,
cool and lubricate the drillstring and bit.

Drilling fluid circulation
Drilling fluid is forced to circulate in the hole
at various pressures and
flow rates.
Drilling fluid is stored
in steel tanks located beside the rig.
Powerful pumps force the drilling fluid
through surface high pressure connections
to a set of valves called pump manifold,
located at the derrick floor.

Drilling fluid circulation (Cont.)
From the manifold,
the fluid goes up the rig
within a pipe called standpipe
to approximately 1/3 of the height
of the mast.
From there the drilling fluid flows
through a flexible high pressure
hose to the top of the drillstring.
The flexible hose allows the fluid
to flow continuously
as the drillstring moves up and
down
during normal drilling operations.

swivel
The fluid enters in the
drillstring through a special
piece of equipment called
swivel located at the top of the
kelly.
The swivel permits rotating the
drillstring while the fluid is
pumped through the drillstring.
A swivel

drilling fluid in wellbore
In wellbore
The drilling fluid then flows down
the rotating drillstring and
jets out through nozzles in the drill bit
at the bottom of the hole.
The drilling fluid picks the rock cuttings
generated by the drill bit action on the formation.
The drilling fluid then
flows up the borehole through
the annular space
between the rotating drillstring and borehole wall.

drilling fluid at surface
At surface
At the top of the well (and above the tank level),
the drilling fluid flows through the flow line
to a series of screens called the shale shaker.
The shale shaker is designed to
separate the cuttings from the drilling mud.
Other devices are also used to clean the drilling fluid
before it flows back into the drilling fluid pits.

Process of mud circulation
The principal
components of the mud
circulation system are:
pits or tanks,
pumps,
flow line,
solids and contaminants
removal equipment,
treatment and mixing
equipment,
surface piping and valves,
the drillstring.
Rig circulation system

The tanks
The tanks
(3 or 4 – settling tank, mixing tank(s), suction tank)
are made of steel sheet.
They contain a safe excess (neither to big nor to small)
of the total volume of the borehole.
In the case of loss of circulation,
this excess will provide the well with drilling fluid
while the corrective measures are taken.
The number of active tanks depends on
the current depth of the hole
(bypasses allow to isolate one or more tanks.)
The tanks will allow enough retaining time so that
much of the solids brought from the hole
can be removed from the fluid.

SETTLING SEPARATION
IN NON-STIRRED COMPARTMENTS
The solids control pits work on
an overflow principle.
The sand traps are the first of the solids control pits and
are fed by the screened mud from the shale shakers.
There should be no agitation from suction discharge
lines or paddles.
Any large heavy solids will settle out here and
will not be carried on into the other pits.

Mixing and suction tanks

MUD HANDLING EQUIPMENT
Rig sizing must incorporate
mud handling equipment as
these equipment determine the
speed of drilling and the quality
of hole drilled.
The equipment includes:
Shale Shakers
The type of mud (i.e. oil-based or
water-based) determines the type
of the shaker required and the
motion of the shaker. Deep holes
require more than the customary
three shakers.

MUD HANDLING EQUIPMENT (Cont.)
Mud Pits
The number and size of pits is
determined by the size and depth
of hole.
Other factors include: size of rig
and space available, especially on
offshore rigs. The size of a mud pit
is usually 8-12 ft wide, 20-40 ft long
and 6-12 ft high.
Mud degasser
Centrifuges and mud cleaners
Desanders and desilters

reciprocating positive displacement
pumps vs. centrifugal pumps
The great majority of the pumps
used in drilling operations are
reciprocating positive displacement pumps (PDP).
Advantages of the reciprocating PDP when
compared to centrifugal pumps are:
ability to pump fluids with high abrasive solids contents
and with large solid particles,
easy to operate and maintain,
sturdy and reliable,
ability to operate
in a wide range of pressure and flow rate.

positive displacement pumps
compartments
PDP are composed of two major parts, namely:
Power end:
receives power from engines and transform the rotating
movement into reciprocating movement.
The efficiency Em of the power end,
• that is the efficiency with which rotating mechanical power is
transformed in reciprocating mechanical power
• is of the order of 90%.
Fluid end:
converts the reciprocating power into pressure and flow rate.
The efficiency Ev of the fluid end
(also called volumetric efficiency),
• that is, the efficiency that the reciprocating mechanical power is
transformed into hydraulic power, can be as high as 100%.

Pump configurations
Rigs normally have two or three PDPs.
During drilling of shallow portions of the hole,
when the diameter is large,
the two PDPs are connected in parallel
to provide the highest flow rate necessary
to clean the borehole.
As the borehole deepens,
less flow rate and higher pressure are required.
In this case, normally only one PDP is used
while the other is in standby or in preventive
maintenance.

Affecting parameters on flow rate
The great flexibility in the pressure and flow rate
is obtained with the possibility of
changing the diameters of the pair piston–liner.
The flow rate depends on the following
parameters:
stroke length LS (normally fixed),
liner diameter dL,
rod diameter dR (for duplex PDP only),
pump speed N (normally given in strokes/minute),
volumetric efficiency EV of the pump.
In addition, the pump factor Fp is defined as
the total volume displaced by the pump in one stroke.

Types of
the positive displacement pumps
The heart of the circulating system is
the mud pumps.
There are two types of PDP:
double-action duplex pump, and
single-action triplex pump.
Triplex PDPs, due to several advantages,
(less bulky, less pressure fluctuation,
cheaper to buy and to maintain, etc,)
has taking place of the duplex PDPs
in both onshore and offshore rigs.

CENTRIFUGAL PUMPS
This type uses an impeller
for the movement of fluid
rather than a piston reciprocating
inside a cylinder.
Centrifugal pumps are used
to supercharge mud pumps and
providing fluid to
solids control equipment and
mud mixing equipment.

Duplex vs. Triplex pumps
A basic pump consists of a piston (the liner)
reciprocating inside a cylinder.
A pump is described as single acting
if it pumps fluid on the forward stroke (Triplex pumps)
and double acting
if it pumps fluid
on both the forward and backward stokes (Duplex).

Duplex pumps
Piston scheme (double action) A duplex unit

Triplex pumps
Piston scheme (single action). A Triplex unit

Pump liners
Pump liners fit inside the pump
cavity.
These affect the pressure rating and
flow rate from the pump.
For a given pump, a liner has the
same OD but with different internal;
diameters.
The smaller liner (small ID) is used in
the deeper part of the well where
low flow rate is required but at
much higher operating pressure.
The size of the pump
is determined by the length of
its stroke and the size of the liner.

the pump factor
The duplex mud pump consists of
two double–action cylinders.
This means that drilling mud is pumped
with the forward and backward movement of the barrel.
For a duplex pump (2 double–action cylinders) the pump
factor is given by:
The triplex mud pump consists of
three single–action cylinders.
This means that drilling mud is pumped only in the
forward movement of the barrel.
For a triplex pump the pump factor is:

VOLUMETRIC EFFICIENCY
Drilling mud usually contain little air and
is slightly compressible.
Hence the piston moves through a shorter stroke than
theoretically possible before reaching discharge
pressure.
As a result the volumetric efficiency is always less than
one; typically 95% for triplex and 90% for duplex.
In addition due to power losses in drives,
the mechanical efficiency of most pumps is about 85%.

Pump Flow Rate
For both types of PDP, the flow rate is calculated
from:
For N in strokes per minute (spm), dL, dR, and LS in
inches, Fp in in3, and q in gallons per minute (gpm)
we have:
Note that in this particular formulation,
the volumetric efficiency of the pump
is included in the pump factor.

Pump operating pressure
The horse power requirements of the pump
depends on the flow rate and the pressure.
The operating pressure depends on
flow rate, depth and size of hole, size of drillpipe and
drillcollars, mud properties and size of nozzles used.
A full hydraulics program needs to be calculated to
determine the pressure requirement of the pump.

Pump Power
Pumps convert mechanical power into hydraulic
power. From the definition of power P=Fv
In its motion,
the piston exerts a force [F] on the fluid that is equal to
the pressure differential in the piston Δp times
the area A of the piston, and
the velocity v is equal to
the flow rate q divided by the area A, that is
For PH in hp, p in psi, and q in gal/min (gpm) we have:

pump factor & hydraulic
power
Compute the pump factor in gallons per stroke and
in barrels per stroke for a triplex pump having
5.5 in liners and
16 in stroke length,
with a volumetric efficiency of 90%.
At N = 76spm, the pressure differential between
the input and the output of the pump is 2400 psi.
Calculate
the hydraulic power transferred to the fluid, and
the required mechanical power of the pump if Em is 78%.

pump factor & hydraulic
power
The pump factor (triplex pump) in in3 per stroke is:
Converting to gallons per stroke and to barrels per
stroke gives:
The flow rate at N = 76spm is:
The hydraulic power transferred to the fluid is:
To calculate the mechanical power required by the
pump we must consider the efficiencies:

Surge Dampeners
Due to the reciprocating action of the PDPs,
the output flow rate of the pump presents a
“pulsation” (caused by the changing speed of the
pistons as they move along the liners).
This pulsation is detrimental
to the surface and downhole equipment
(particularly with MWD pulse telemetry system).
To decrease the pulsation,
surge dampeners are used at the output of each pump.

schematic of a typical surge dampener
A flexible diaphragm
creates a chamber filled
with nitrogen at high
pressure.
The fluctuation of
pressure is compensated
by a change in the
volume of the chamber.
A relief valve located in
the pump discharge line
prevents line rupture in
case the pump is started
against a closed valve.
Surge dampener

aim of the solids removal system
Fine particles of inactive solids
are continuously added to the fluid during drilling.
These solids increase the density of the fluid and
also the friction pressure drop, but
do not contribute to the carrying capacity of the fluid.
The amount of inert solids must be kept as low as possible.
Recall mud is made up of
fluid (water, oil or gas) and solids (bentonite, barite etc).
The aim of any efficient solids removal system is
to retain the desirable components of the mud system
by separating out and discharging
the unwanted drilled solids and contaminants.

Solids in drilling fluids classification:
based on specific gravity, (or density)
Solids in drilling, classified by specific gravity, may
be divided into two groups:
High Gravity Solids (H.G.S.) sg = 4.2
Low Gravity Solids (L.G.S.) sg = 1.6 to 2.9
The solids content of a drilling fluid will be made up
of a mixture of high and low gravity solids.
High gravity solids (H.G.S) are added to fluids
to increase the density,e.g. barytes,
whilst low gravity solids (L.G.S)
enter the mud through drilled cuttings and
should be removed by the solids control equipment.

Solids in drilling fluids classification:
based on particle size
Mud solids are also classified according
to their size in units called microns (µ).
A micron is 0.0000394 in or 0.001 mm.
Particle size is important in drilling muds
for the following reasons:
The smaller the particle size,
the more pronounced the affect on fluid properties.
The smaller the particle size,
the more difficult it is to remove it or
control its effects on the fluid.

particle size classification
The API classification of particle sizes is:
Particle Size (µ) Classification Sieve Size (mesh)
> 2000 Coarse 10
2000 - 250 Intermediate 60
250 - 74 Medium 200
74 – 44 Fine 325
 44 - 2 Ultra Fine -
 2 - 0 Colloidal -

solids control equipment
Solids contaminants and gas entrapped in mud can
be removed from mud in four stages:
Screen separation:
shale shakers, scalper screens and mud cleaner screens.
Settling separation in non-stirred compartments:
sand traps and settling pits.
Removal of gaseous contaminants
by vacuum degassers or similar equipment
Forced settling by the action of centrifugal devices
including hydrocyclones (desanders, desilters and micro-cones)
Mud cleaners and centrifuges.

Complete mud removal system
with mud cleaner and centrifuge

sketch of
a typical solids control system
Figure shows
a sketch of a
typical solids
control system
(for
unweighted
fluid).

a typical two–screen shale shaker
The screens
are vibrated by
eccentric heavy
cylinders
connected to
electric motors.
The vibration
promotes an
efficient
separation
without loss of
fluid.
A two–screen shale shaker

Linear shale shaker
The figure
shows
a layout for
solids control
equipment
for
a weighted
mud system.

shale shaker mechanism
The shale shaker
removes
the coarse solids
(cuttings) generated
during drilling.
It is located at the
end of the flow line.
It constitutes of
one or more
vibrating screens in
the range of
10 to 150 mesh
over which the mud
passes before it is
fed to the mud pits.
Shale shaker configurations

The procedure
Shale shakers and scalper screens (Gumbo shakers)
can effectively remove up to 80% of all solids from a
drilling fluid,
if the correct type of shaker is used and
run in an efficient manner.
Removal procedure:
Mud laden with solids passes over the vibrating shaker
where the liquid part of mud and small solids
pass through the shaker screens and
drill cuttings collect at the bottom of the shaker
to be discharged.

types of shaker operation
There are two types of
shaker operation:
elliptical shakers and
Field experience indicate
they work better with
water based muds
linear motion shakers.
more suited
to oil based muds.
An absolute minimum of
three shale shakers is
recommended and that
these shakers are fitted
with retrofit kits
to allow quick and simply
replacements.
The shakers should also
be in a covered,
enclosed housing
with a means of
ventilation and
each shaker
fitted with a smoke hood.

Sample of shale shakers

Degassers
Gases that might enter the fluid
must also be removed.
Even when the fluid is overbalanced,
the gas contained in the rock cut by the bit
will enter the fluid and must be removed.
The degasser removes gas from the gas cut fluid
by creating a vacuum in a vacuum chamber.
The fluid flows down an inclined flat surface
as a thin layer.
The vacuum enlarges and coalesce the bubbles.
Degassed fluid is draw from chamber
by a fluid jet located at the discharge line.

Vacuum degasser
The combination of
low internal pressure and
thin liquid film
causes gas bubbles to
expand in size,
rise to the surface of
the mud inside the vessel
and break from the mud.
As the gas moves toward
the top of the degasser
it is removed
by the vacuum pump.
The removed gas is
routed away from the rig
and is then either vented
to atmosphere or flared.

A typical degasser diagram
(A vacuum chamber degasser)

FORCED SETTLING BY CENTRIFUGAL
DEVICES
Desanders and desilters are hydrocyclones and
work on the principle of separating solids from a liquid
by creating centrifugal forces inside the hydrocyclone.
Hydrocyclones
are simple devices with no internal moving parts.
are classified according to the removed particle size as
desanders (cut point in the 40–45μm size range) or
desilters (cut point in the 10–20μm size range).
At the cut point of a hydrocyclone
50% of the particles of that size is discarded.

The process of the Hydrocyclones
(Desanders and Desilters)
Mud is injected tangentially
into the hydrocyclone
the resulting centrifugal
forces
drive the solids to the walls
of the hydrocyclone and
 finally discharges them from
the apex
with a small volume of mud.
The fluid portion of mud
 leaves the top of the
hydrocyclone as an overflow
and
 is then sent to the active pit
to be pumped downhole
again.

Desanders
The primary use of desanders is
in the top hole sections
when drilling with water based mud
to help maintain low mud weights.
Desanders
should be used if the sand content of the mud rises
above 0.5% to prevent abrasion of pump liners.
should never be used with oil based muds,
because of its very wet solids discharge.

The desander
It is a set of two or
three 8in or 10in
hydrocyclones,
and are positioned
after
the shale shaker and
the degasser (if used).

Desilters
The desilter
is a set of eight to twelve 4in or 5in hydrocyclones.
It removes particles that can not be removed by the desander.
Desilters, in conjunction with desanders, should be
used to process low mud weights used to drill top hole
sections.
If it is required to raise the mud weight this must be
done with the additions of barytes, and not by allowing
the build up of low gravity solids.
Desilters should never be used with oil based muds.

Solid control equipment
Typical throughput
capacities are:
Desanders
12"cone
500 gpm per cone.
6" cone
125 gpm per cone.
Desilters
4"cone
50 gpm per cone.
2" cone
15 gpm per cone.
(b) Desilter

Particle size classification
A typical
drilling solid
particle
distribution
and particle
size range
classification
are shown in
the diagram.
The diagram
includes the
particle size
distribution of
typical
industrial
barite used in
drilling fluids.

Decanting centrifuge
The centrifuge is a solids control equipment
which separates particles even smaller,
which can not be removed by the hydrocyclones.
It consists of a rotating cone–shape drum,
with a screw conveyor.
Drilling fluid is fed through the hollow conveyor.
The drum rotates at a high speed and creates a
centrifugal force that causes the heavier solids to decant.
The screw rotates in the same direction of the drum
but at a slight slower speed,
pushing the solids toward the discharge line.
The colloidal suspension exits the drum
through the overflow ports.

Internal view of a centrifuge
The drums
are enclosed
in an external,
non–rotating
casing
not shown in
the figure.

Mud Cleaners
A mud cleaner
is a desilter unit in which
the underflow is further processed
by a fine vibrating screen,
mounted directly under the cones.
The use of mud cleaners with oil based muds
should be minimized since
experience has shown that mud losses of 3 to 5 bbls/hr
being discharged are not uncommon,
coupled with the necessity to adhere to strict
environmental pollution regulations.

mud cleaner
Inert solids in weighted fluid
(drilling fluid with weight
material like
barite, iron oxide, etc)
can not be treated with
hydrocyclones alone
because the particle sizes of the
weighting material are within the
operational range of desanders
and desilters.
Weighting material are relatively
expensive additives, which must
be saved.

mud cleaner schematic
The mud
cleaner
separates
the low
density inert
solids
(undesirable)
from the
high density
weighting
particles.
Unit of a mud cleaner

Hydrocyclones
Hydrocyclones discriminate light particles from
heavy particles.
Bentonite are lighter than formation solids
because they are of colloidal size
(although of the same density).
Barite particles are smaller than formation solids
because they are denser.
The desilter
removes the barite and
the formation solids particles in the underflow,
leaving only a clean mud
with bentonite particles
in a colloidal suspension in the overflow.

Hydrocyclones (Cont.)
The thick slurry in the underflow
goes to the fine screen,
which separate the large (low density) particles
(formation solids)
from the small (high density) barite particles,
thus conserving weighting agent and the liquid phase
but at the same time returning many fine solids to the
active system.
The thick barite rich slurry is treated with dilution
and mixed with the clean mud (colloidal bentonite).
The resulting mud is treated
to the right density and viscosity and
re–circulates in the hole.

Principle of the mud cleaner
Mud cleaners
 are used mainly
with oil– and
synthetic–base
fluids
where the liquid
discharge from
the cone cannot
be discharged,
either for
environmental
or economic
reasons.
 may also be
used with
weighted
water–base
fluids
 to conserve
barite and the
liquid phase.
A diagram of a mud cleaner

Drilling fluid components
Drilling fluid is usually a suspension of clay
(sodium bentonite) in water.
Higher density fluids can be obtained
by adding finely granulated (fine sand to silt size)
barite (BaSO4).
Various chemicals or additives are also used
in different situations.
The drilling fluid continuous phase is usually water
(freshwater or brine) called water–base fluids.
When the continuous phase is oil
(emulsion of water in oil) it is called oil–base fluid.

Mixing Equipment
Water base fluids are normally made at the rig site
(oil base mud and synthetic fluids
are normally manufactured in a drilling fluid plant).
Special treatment and
mixing equipment exists for this purpose.
Tank agitators, mud guns, mixing hoppers, and
other equipment are used for these purposes.

drilling fluids physical properties
blenders
The basic drilling fluids physical properties are density,
viscosity, and filtrate.
Fresh water density is 8.37 pounds per gallon (ppg).
Bentonite adds viscosity to the fluids and also increases the
density to about 9 to 10 ppg.
Higher density (15 to 20 ppg) is obtained with barite, iron
oxide, or any other dense fine ground material.
Tank agitators or blenders
are located in the mud tanks
to homogenize the fluid in the tank.
help to keep the various suspended material
homogeneously distributed in the tank
by forcing toroidal and whirl motions of the fluid in the tank.

Mud agitator
Tank agitators or blenders toroidal and whirl motions

Sample of Mud agitator

Mud guns
Mud guns
are mounted in gimbals
at the side of the tanks,
allow aiming a mud jet
to any point in the tank
help to homogenize the
properties of two tanks,
and spread liquid
additives in a large area
of the tank
(from a pre-mixed tank).
Centrifugal pumps
power the mud guns.
Mud gun

mixing hopper
The mixing hopper
allows adding powder substances and
additives in the mud system.
The hopper is connected to a Venturi pipe.
Mud is circulated by centrifugal pumps and
passes in the Venturi at high speed,
sucking the substance into the system.

Mud hopper

Chapter 16 and 7

1. The Rotary System
A. Introduction
B. Kelly, Kelly Valves, and Kelly Saver Sub
C. Rotary Table and Components
D. The topdrive

Introduction
The rotary system is the set of equipment
necessary to promote the rotation of the bit.
The bit must be
mechanically and
hydraulically connected to the rig.
This connection is made by the drillstring.
The purpose of the drillstring is
to transmit axial force,
torque, and drilling fluid (hydraulic power)
to the bit.

Drillstring components
The basic drillstring is
composed of the following
components:
Swivel,
Kelly and accessories,
Rotary table and components,
Drillstring tubulars
(drill pipe, drill collars, etc.),
BHA
Drill bit.

The main components of rotating
equipment
The main components are:
Rotary table
Kelly
Top Drive
equivalent to the Kelly and rotary
table, i.e. either top drive or
Kelly/rotary table
Swivel
Rotary hose
The rotary horse power
requirement is usually between
1.5 to 2 times the rotary speed,
depending on hole depth.
Hence for rotary speed of 200 rpm,
the power requirement is about 400
HP.

Swivel
The swivel
is suspended by the hook of
the traveling block and
allows the drillstring to rotate
as drilling fluid is pumped
to within the drillstring.
supports the axial load of the
drillstring.
Without the swivel,
drilling fluid could not be
pumped downhole,
or the drillstring could not
rotate.
A flexible hose connects to
the gooseneck
which is hydraulically coupled
to the top of the swivel stem
by a stuffing box.
The stem shoulder
rest on a large thrust tapered
roller bearing,
which transmits the drillstring
weight to the swivel body, and
then to the bail.
The thread connector of the
swivel
is cut left–hand so that
it will not tend to disconnect
when the drillstring is rotated
by the kelly or
by the top drive.

cuts of a swivel
showing the internal parts

KELLY vs. TOP DRIVE
Strictly speaking the Kelly or
top drive are not components of
the drill string.
The Kelly is
the rotating link between
the rotary table and the drill string.
Its main functions are:
transmits rotation and
weight-on-bit to the drillbit
Supports the weight of the drillstring
connects the swivel to the uppermost
length of drillpipe; and
conveys the drilling fluid from the
swivel into the drill string.

kelly
Below and connected to the swivel is
a long four-sided (square) or triangular or
six-sided (hexagon, the most common) steel bar
with a hole drilled through the middle
for a fluid path called kelly.
The square or hexagonal section of the kelly
allows it to be gripped and turned
by the kelly bushing and rotary table.
The Kelly comes
in lengths ranging from 40 to 54 ft (12 to 16.5 m)

The purpose of the kelly
The purpose of the kelly is
to transmit
rotary motion and torque
to the drillstring
(and consequently
to the drill bit),
while allowing the drillstring
to be lowered or raised
during rotation.
A square kelly and
a hexagonal kelly

kelly bushing
Torque is transmitted
to the kelly
by the kelly bushing. It
has an inside profile
matching the kelly’s
outside profile (either
square or hexagonal),
but with slightly larger
dimensions
so that the kelly
can freely move up and
down inside it.
Kelly bushings

Applications of the kelly valves
The kelly valve consists of
a ball valve which allows free
passage of drilling fluids without
pressure loss.
This is a safety device
can be closed to prevent flow from
inside the drillstring during critical
operations like kick control.
It also
isolates the drillstring
from the surface equipment and
allows disconnecting
the kelly during critical operations.
A kelly valve

The Kelly cocks (the kelly valves)
The Kelly is usually provided
with two safety valves,
one at the top and
one at the bottom,
called upper and lower Kelly cocks,
respectively.
The upper kelly valve
has left–hand threads
The lower Kelly cock
is always manual

kelly saver sub
A kelly saver sub is simply a short length pipe with
has male threads on one end
and female on the other.
It is screwed onto the bottom of the lower kelly valve or
top drive and onto the rest of the drillstring.
When the hole must be deepened,
and pipe added to the drillstring,
the threads are unscrewed between
the kelly saver sub and the rest of the drillstring,
as opposed to between the kelly valve or
top drive and the saver sub.

kelly saver sub (Cont.)
This means that the connection between the kelly or
top drive and the saver sub rarely is used,
and suffers minimal wear and tear,
whereas the lower connection is used in almost all cases and
suffers the most wear and tear.
The saver sub is expendable and
does not represent a major investment.
However, the kelly or top drive component threads
are spared by use of a saver sub, and
those components represent a significant capital cost and
considerable downtime when replaced.
It is important that
both lower kelly valve and kelly saver sub
be of the same diameter of the drill pipe tool-joints
to allow stripping into the hole during control operations.

master bushing and master casing
bushing
The kelly bushing fits in
the master bushing,
which, in turn, attach to
the rotary table.
It connects to the master
bushing either by pins of
by a squared link.
The master bushing
transmit torque and
rotation from the rotary
table to the kelly bushing.
A master casing bushing
is used to handle casings.
Master bushings, and casing bushing

Kelly bushing and master bushing
Figure shows
a kelly
bushing,
master
bushing, and
rotary table
assembly.

Drillpipe slip (detail when
set in the master bushing)
The master bushing
(and also the master casing bushing) has
a tapered internal hole.
 The purpose of the tapered hole is to
receive the pipe slips.
 During pipe connection or
drillstring trip operations,
this tapered hole receives either
the drill pipe slips, or the drill collar slips,
or the casing slips,
which grips the tubular and
frees the hook from its weight.
Because of
the slick shape of most drill collars,
 a safety clamp is always used above the
drill collar slips (mandatory!)
 If the drill collars slides in the slips,
the safety clamp works as a stop to force
the slips to grip the drill collar.

DC slips, safety collar, casing slips and
A rotary table
A drill collar slips (a),
a safety collar (b), and
a casing slips (c) are
shown in the Figure.
The rotary table
receives power from
the power system
(either mechanical or
electric.)
A gearbox allows
several combinations of
torque and speed.

Kelly set

The top drive outlook
The top drive is basically a
combined rotary table and
Kelly.
The top drive
consists of a DC drive motor that
connects directly to the drillstring
without the need or a rotary
table.
The top drive
is mounted on the rig’s swivel,
the swivel attaches to
the travelling block and
supports the drillstring weight.

The elevator and elevator links
of a topdrive
The top drive has
a pipe handler consisting of a
torque wrench and
a conventional elevator
to assist in pipe handling during
connection and
round trip operations.
The elevator and elevator links
are supported on a shoulder
located on
the extended swivel stem.

Different positions of a topdrive

Advantages of topdrive
The top drive functions is the
same way as the Kelly.
However, it has
many advantages over
the Kelly system including
circulating while back reaming,
circulating while running in hole
or pulling out of hole in stands.
The Kelly system can only do this
in singles; i.e. 30 ft.

Chapter 16 and 10

1. Well Control System
2. Well Monitoring System

well control & kick
The functions of the well control system are
to detect, stop, and remove any undesired
entrance of formation fluids into the borehole.
An undesired entrance of formation fluid
into the borehole is called kick and
may occur due to several reasons
(high pressure formations,
insufficient drilling fluid density,
drillstring swab,
loss of circulation,
formation fracture,
etc).

blowout
If the undesired entrance of fluid feedbacks and
the fluid continuously enters the borehole
reaching the surface,
it is called blowout.
Blowouts (in particular gas blowouts)
are extremely dangerous and
put the crew, the rig, the drilling operation, and
the reservoir at risk.

well control system constituent
The well control system must
detect, control, and remove
the undesired entrance of fluids into the borehole.
The system is composed of
sensors (flow rate, surface volume, annular and
drillstring pressure, and etc,) capable to detect
an increase of flow or volume in the fluid system,
the blowout preventer (BOP),
the circulating pressure control manifold
(choke manifold),
and the kill and choke lines.

the blowout preventer (BOP)
The BOP is a set of pack–offs capable of shutting
the annular space between the surface casing and
the drillstring.
Because of the diversity in shape of the annular,
several different device types exist and
they are normally assembled together
(and in various configurations) called BOP stack.
The BOP stack is located
under the rotary table
in land and fixed marine rigs,
and on the bottom of the sea
in mobile and floating rigs.

PRESSURE CONTROL EQUIPMENT
BOPs equipment are selected
based on the maximum expected
wellbore pressures.
The pressure rating, size and
number of BOP components must
be determined by the Drilling
Engineer prior to drilling the well.
BOPs are rated by API as
3M (3000 psi), 5M, 10 M and 15 M.
For HPHT, BOPS are either
15 M or 20 M.

BOP stacks
A fixed rig BOP A floating rig BOP

Sample of a land rig BOP Stack

the BOP stack In subsea operations
In subsea operations,
the BOP stack is installed at seabed.
The stack has several back up units in case of failure,
for example two annulars are used so that if one failed
the other can be used.
This back-up system principle is applied to all the BOP
components.
The subsea stack for HPHT operation
may not be part of the rig contract and
may have to be rented out separately, e.g. a 20K stack.

Annular BOP’s
The various types of BOP
devices are:
Annular BOP, Blind ram, Pipe
rams, and Shear rams
Annular BOP:
The purpose of the annular
BOP is to shut the annular
in front of any kind of
drillstring equipment
(except stabilizers) or
even without drillstring.
The active element is an
elastomeric ribbed donut
that is squeezed around
the drillstring
by an hydraulic ram.
It is located
at the top of the BOP stack.

an inside BOP
Controlling the pressure applied
to the ram, it is possible to strip
the drillstring in and out while
keeping the annular closed
(requires the use of an inside-BOP,
which should be connected
immediately to the drillstring
when a kick is identified).
The inside BOP acts as a check
valve, allowing fluid be pumped
down the drillstring,
but blocking back flow.

Blind & Pipe rams
Blind ram:
The blind rams (normally one at the top of all other rams)
allows shutting the borehole with no drillstring element in
front of it. (the upper ram in the figure)
If the blind ram is applied to a drillpipe, the pipe
will be flatten but no seal is obtained.
Pipe rams:
The pipe rams allows shutting the annular
in front a compatible drill pipe (not in front of tool joints.)
Normally two rams are used
a special spool between the two is used where the kill and
choke line is connected. (the lower ram in the figure)
The use of two pipe rams also
permit to snub the drillstring during the well control operation.

shear rams
Shear rams:
The shear ram
(normally one below the
blind ram or below all
other rams) can shear a
drill pipe and provide seal.
This is a last resource
when all other rams and
annular had failed.
Circulation through the
drillstring is lost and,
if the shear ram is the
lower one,
the drillstring falls into the
borehole.

BOP control panels
All these safety devices
are hydraulically actuated
by a pneumatic–hydraulic
system
(actuators and
accumulators),
which can operate
completely
independent of the power
system of the rig.
Two control panels are
normally used,
one at the rig floor,
and a remote one away
from the risky area.
BOP accumulators and control panels

The accumulators
The accumulators are steel bottles lined
with a elastomeric bladers
forming two separated compartments.
One compartment is filled with oil,
which powers the BOP.
The other compartment is filled with air or nitrogen
at high pressure.
The pressure of the gas pressurizes
the oil across the elastomeric liner.
Rig power, during ordinary operation,
keeps the gas in the accumulators under pressure.
The accumulators should be able
to provide hydraulic power to close and open all elements
of the BOP stack a number of times without external power.

Sample of BOP control panel & the
accumulator

Choke Manifold
During a kick control operation, some of the BOP
stack devices are actuated
to close the annulus and
divert the returning fluid to the choke line.
The choke line directs the returning fluid to a manifold
of valves and chokes called choke manifold,
which allows to control the flow pressure
at the top of the annular adjusting the flow area open to flow.
The choke manifold also direct the flow
• to a flare (in case of a gas kick), or
• to the pits (if mud) or
• to special tanks (if oil)

Choke manifold

Sample of a choke manifold

data required to control of operations
under way in the rig
Several sensors, gauges,
meters, indicators, alarms,
and recorders exist
in the rig to provide all
data required to control
(safely, efficiently, and
reliably) of all operations
under way in the rig.
Among the most
important parameters are:
weight on bit (WOB) and
hook load,
rate of penetration (ROP),
rotary speed,
torque,
circulating (pump) pressure,
flow rate (in and out),
drilling fluid gain/loss,
mud temperature,
mud density,
total hydrocarbon gas
in the drilling fluid.

indication of
hook load and weight on bit
Accurate and reliable indication
of hook load and weight on bit are essential for
the efficient control of rate of penetration, bit life, borehole
cleaning, and borehole direction.
The weight indicator works
in conjunction with the deadline anchor
using either tension or compression hydraulic load cells.
The deadline anchor senses the tension in the deadline and
hydraulically actuates the weight indicator.
Most weight indicators have two hands and two scales.
The inner scale shows the hook load and
the outer one shows the weight-on–bit.

Weight indicator and
a deadline anchor
Weight indicator a deadline anchor

weight–on–bit
To obtain the weight–on–bit,
the driller perform the following steps:
with the bit out of the bottom,
the drillstring is put to rotate and
the weight of the drillstring is observed in the central scale;
using the knob at the rim of the weight indicator,
the outer scale is adjusted so that
the zero of the outer scale aligns with the longer hand.
The driller lowers the drillstring slowly observing the long
hand.
When the bit touches the bottom, part of the weight of the
drillstring is transferred from the hook to the bit
(the weight–on–bit.)
The amount of weight transferred corresponds to
the decrease of hook load,
indicated by the long pointer (turning counterclockwise).

control consoles
All modern rigs have control consoles that
shows all pertinent parameters in analog and
or digital displays.
All parameters and operations may be
recorded in physical (paper) or
magnetic media for post analysis.
Some automated operations like
constant weight–on–bit and
constant torque are possible in most rigs.

Drilling control console

Q931+de1 reference en lecs

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