Q931+de1 reference en lec 4x1

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
‫ﯾﮏ‬ ‫ﺣﻔﺎرى‬ ‫ﻣﻬﻨﺪﺳﻰ‬ ‫ﮐﻼﺳﻰ‬ ‫ﻫﺎى‬ ‫اراﺋﻪ‬ ‫ﮐﺎﻣﻞ‬ ‫ﻣﺠﻤﻮﻋﻪ‬ ‫ﻗﻮﭼﺎن‬ ‫واﺣﺪ‬ ‫اﺳﻼﻣﻰ‬ ‫آزاد‬ ‫داﻧﺸﮕﺎه‬ - ‫ﻧﯿﺎ‬ ‫اﻋﻠﻤﻰ‬ ‫ﺣﺴﯿﻦ‬ :‫ﻣﺪرس‬
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Hossein
AlamiNia
Digitally signed by Hossein
AlamiNia
DN: cn=Hossein AlamiNia,
o=IAUQ, ou=Chemical &
Petroleum Engineering
Department,
email=H.AlamiNia@Gmail.Com
, c=IR
Date: 2014.12.27 11:07:24
+03'30'

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.
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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)
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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
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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
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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
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)1390(
:
:
)1(
)1390) ((
:
:
)1(
)1390) ((
Drag
Bit
IADC
PDC
:
Extra (Beyond scope)
Simulating experiments using relevant software
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)1(
)1390(
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
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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)
)(
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:
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.
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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
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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
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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.
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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
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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
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Marine:
Other Bottom Supported rigs
Marine: Floating rigs
Diagram of a
spar–buoy
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.
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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.
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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.
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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.
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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.
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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
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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.
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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.
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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.
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Calculations of
planned drilling times
Solution:
Example 17.1: Calculation of time depth curve,
WEC PGO: 752
Time depth calculations
Time depth curve
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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
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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.
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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
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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.
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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.
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Chapter 17
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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
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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.
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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.
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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
Gasoline
Butane
(liquid)
Methane
(gas)
–
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:
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:
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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:
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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
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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.
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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.
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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 ".
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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.
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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:
If the breaking strength of the drilling line is known,
then a design factor, DF, may be calculated as follows:
Lowering Operations:
During lowering of pipe,
the efficiency factor is:
And fast line load is:
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:
In the Imperial system, power is quoted in horse power and the
above equation becomes:
The proof has mentioned in the following slides:
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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:
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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
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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.
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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.
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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
Technology, 2007. Chapter 2
Chapter 16
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
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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.
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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
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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.
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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%.
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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.
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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
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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.
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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 p 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:
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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.
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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
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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
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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.
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Q931+de1 reference en lec 4x1

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