Q931+de1 reference en lecs

Drilling Engineering 1 Course3rd Ed. , 3rd Experience

http://www.iauq.ac.ir/


mailto:[email protected]

http://bit.ly/Q931-RRL

http://about.me/Alaminia




http://about.me/alaminia


1. About This Course

2. Course Learning Outcome

3. Presentation and assessmentA. 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 skillsCommunicate

successfully and effectively.

Understand professional and ethical responsibilities.

Work in a team environment

Familiarize with English language

Academic skillsSystematic research

Reporting

Management skillsProject time

Computer knowledgeUnderstand the use of

modern techniques, skills and modern engineering toolsApplication of internet

and EmailMicrosoft OfficeProfessional 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 timeWould 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)

AttendanceClass activities

Class ProjectsExaminations

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 percentageStudents 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


(1)سرفصل درس مهندسی حفاری (1390مصوب وزارت علوم )مقدمه :

بررسی اجمالی عملیات حفاری واهمیت آن مراحل مختلف توسعه

میدان و نقش حفاری تقسیم بندی انواع چاهها معرفی پرسنل حفاری در

های کارفرما و پیمان کار شرکت وظایف شرکتهای سرویس دهنده اقتصاد حفاریهای انواع قراردادهای حفاری دکل

حفاری

دکل حفاریهای حفاریدسته بندی انواع دکل

در خشکی و فراساحلی های حفاری در نحوه انتخاب دکل

خشکی و دریا اجزائ اصلی دکلهای حفاری و

:محاسبات اصلی هر جزء سیستم مولد نیرو سیستم باال برندهاری سیستم گردش و تصفیه گل حف سیستم دورانی سیستم کنترل فورانسیستم ابزار دقیق و نشانگر ها


(1)سرفصل درس مهندسی حفاری (ادامه( )1390مصوب وزارت علوم )های حفاریرشته

وظایفهای حفاری و مشخصات آنها لولههای وزنه و مشخصات آنها لوله محاسبات مربوط به طراحی

:یک رشته حفاری ضریب شناوریته محاسبه توزیع تنش در امتداد رشهای وزنهمحاسبه طول الزم از لوله نقطه خنثی تعیین حداکثر طول

های حفاری از هر گرید لوله لوله

تعیین حداکثر میزان کشش مجازدر هنگام گیر لوله ها

اجزاء دیگر رشته حفاری : ،ضربه زنها ،پایدار کننده ها،ریمرها آشنایی با موتورهای درون چاهی و

توربین ها


(1)سرفصل درس مهندسی حفاری (ادامه( )1390مصوب وزارت علوم )های حفاریتکنولوژی مته

های سه کاجه و انواع متهDrag Bit و مکانیزم کندن هر یکهای سه ساختمان داخلی مته

کاجه لیت طبقه بندی سازند بر حسب قاب

حفاری عوامل موثر بر سرعت حفاری عوامل موثر بر فرسایش متهها بر اساس طبقه بندی مته

IADCاستاندارد

ها ارزیابی مته

های الماسه و متهPDC

مقدمه ای بر سیاالت حفاری: وظایف طبقه بندیهای اصلی افزایهسیاالت نیوتنی و غیر نیوتنیاهداف هیدرولیک


Extra (Beyond scope)

Simulating experiments using relevant software


(1)منابع پیشنهادی درس مهندسی حفاری (1390مصوب وزارت علوم )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 classThese 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


https://app.box.com/s/x8zfnxf6fl0mdsrxtkds

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


https://app.box.com/s/22c7uhxv35hv0w78v6lx

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)


(کمکی)منابع فارسی مهندسی حفاری : نام کتاب

کاربردیمحمد نادری، آدام : نام نویسنده

. ، کیت کی.بورگوین جی آر. تیچنورت، . میلهم، مارتین ای

احمد سجادیان، مرتضی : مترجمانابراهیم پور کوجان، سید امید

حمیدیان دیوکالهی، امیر طاهری دهلر

1388چاپ اول(انتشارات)مشتاق دانش : ناشر(فصول یک تا چهار: )جلد اول


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 methodsBreak 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 methodsAppointments

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 relatedResearch study Paper for International

conferencesArticles for national

journals

Avoided helps:Other courses

Sources, exams, exercises, class works and so on

B.Sc. ThesisAside supervised ones

M.Sc. Conquer TraineePrivate classEducational problemsPersonal problemsNational 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 costThereto 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 driveno Rotary bito Rotary nozzle

• Subsurface driveno Turbine drillingo Positive

displacement motor drilling

o Electro motor drilling

Annular drilling• Diamond coring• Shot drilling


drilling technologies (Cont.)

Special techniquesAbrasive 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

JackknifePortable

Mast

Conventional

Marine

Bottom Supported

Platform

Self Contained

Tendered

Barge

Jack-Up Submersible

Floating

Drill ShipSemi

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, calledcompany 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 estimatesA. 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 casingFlat times for nippling up/down BOPs and nippling up

wellheadsCirculation 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 BRT17.5”Hole / 13.375" Casing 1421 m BRT12.25” / 9.625" Casing 2334 m BRT8.5” Hole / 7" Casing 3620 m BRTTotal 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/hr26” Hole 5.5 m/hr17.5”Hole 7.9 m/hr12.25” 4.6 m/hr8.5” 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 rigMarket conditionsLength of contractDays on wellMobilization/

Demobilization of rig and equipment

SupervisionAdditional 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:CommunicationsRig positioning

usually required in offshore operations

Logging (wireline) both open & cased hole

logsMWD/ LWDDownhole MotorsSolids Control EquipmentMud EngineeringDirectional Engineering

Surveying determination of

hole angle and azimuth.includes the cost of single

shots, magnetic multi-shots (MMS) and gyros

CementingMud LoggingFishing

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 EquipmentDownhole EquipmentDrillstring Equipment

Logging equipmentStuckpipe and Fishing of

BHA equipmentCasing Hardware and

Cementing EquipmentFluidsHole problemsWell ControlTesting and Completion

NPT


two major elements of well cost estimatesit 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 costsTangible 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.)

P50This is the key figure in most well cost estimates.

This estimate will be based on known information derived from offset data.

P90This 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 innovationProductivity 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 ProductionIt 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.















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 TypeHeating

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:


1. (CDF) Jorge H.B. Sampaio Jr. “Drilling Engineering Fundamentals.” Master of Petroleum Engineering. Curtin University of Technology, 2007. Chapter 2















1. Hoisting System:A. Introduction

B. The Block & Tacklea. 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 lineThe 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–tackleis 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 ∗ 𝜂𝑛 =

𝑊∗𝜂𝑛

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∗𝜂𝑛 1−𝜂

1−𝜂𝑛

And fast-line load is: 𝐹𝑓 𝑙𝑜𝑤𝑒𝑟𝑖𝑛𝑔 =𝑊∗𝜂𝑛 1−𝜂

1−𝜂𝑛


POWER REQUIREMENTS OF THE DRAWWORKSAs 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

EIn 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 powerSince 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 ftdrillpipe = 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

SoSDL=HL/n+HL+HL/n

The wind load is given by: 0.004 V2 (units: lb/ft2)V is wind speed in miles/hourThe 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 legsThe dead line, however must be

anchored close to one of the remaining two legsThe 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 andThe derrick efficiency factorIf 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 PracticePortions 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 SystemA. Introduction

B. Mud Pumpsa. Duplex PDP & Triplex PDP

C. Solids removal

D. Solid Control Equipmenta. 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 surfaceAt 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 COMPARTMENTSThe 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 PitsThe 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 pumpsThe 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 compartmentsPDP 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 pumpsThe 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 sizeMud 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 systemFigure 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 DEVICESDesanders 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"cone500 gpm per cone.

6" cone125 gpm per cone.

Desilters 4"cone

50 gpm per cone.

2" cone15 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 propertiesblendersThe 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 tankhelp 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




2. (WEC) Rabia, Hussain. Well Engineering & Construction. Entrac Consulting Limited, 2002.Chapter 16 and 7














1. The Rotary SystemA. 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 tableKelly 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 drillbitSupports the weight of the drillstringconnects the swivel to the uppermost

length of drillpipe; andconveys 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 devicecan 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 bushingThe 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 tableA 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.



2. (WEC) Rabia, Hussain. Well Engineering & Construction. Entrac Consulting Limited, 2002.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 pipewill 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 rigSeveral 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 bitAccurate 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




