release of location and well planning

7/29/2019 Release of location and Well Planning

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SUMMER INTERNSHIP

REPORT

Submitted to:

Dr. R. K. Bawa Dr. Sharad Kr. Shankar

General Manager (Chemistry) Dy. General Manager (Chemistry)ONGC, Jodhpur ONGC, Jodhpur

Submitted by :

Prakhar MathurB. Tech. 2nd year (Petroleum Technology)

School of Petroleum TechnologyPandit Deendayal Petroleum University,

Gandhinagar

PANDIT DEENDAYAL PETROLEUM UNIVERSITY


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ACKNOWLEDGEMENT

Apart from the efforts of me, the success of this project depends largely on the

encouragement and guidelines of many others. I take this opportunity to express

my gratitude to the people who have been instrumental in the successful

completion of this project.

I would like to show my greatest appreciation to Dr Sharad Kr. Shankar and

Dr. R. K. Bawa. I cant say thank you enough for tremendous support and help.

I feel motivated and encouraged every time I attend their meeting. Without their

encouragement and guidance this project would not have materialized.

The guidance and support received from all the team members such as ,

Mr. Vikram Saxena , Mr. Atul Kumar and Mr. Baireddy Aneel, was vital for

the success of the project. I am grateful for their constant support and help.

My thanks and appreciation also goes to my colleague in developing the project

and people who have willingly helped me out with their abilities.


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CONTENTS

CONTENTS PAGE NO.

INTRODUCTION OF ONGC 4

WELL PLANNING 11

OVERVIEW OF PLANNING PROCESS 14

GTO 15CASING 16

WELLHEAD SELECTION 20

BOP REQUIREMENT 22

CEMENTING PROGRAMME 23

MUD PROGRAMME 24

BIT AND HYDRAULICS PROGRAMME 26EVALUATION REQUIREMENTS 27

WELL COST ESTIMATION 31

REFERENCES 33


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INTRODUCTION OF ONGC

ONGC - WORLDD NO. 1 E & P COMPANY

ONGC has achieved the distinction of Numero Uno ranking in the pure E & P

category, not only in Asia, but on the global scale. ONGC has been ranked 18th

in the overall listing of global energy companies as per plats top 250 Global

Energy Company Ranking 2010.

PERFORMANCE : 2009-10

Highest reserve accretion in last two decades

ONGC accreted 82.98 Million Tonnes of Oil Equivalent (MTOE) of Ultimate

Reserves (3P) in domestic operated fields-the highest in last two decades. Total

reserve accretion in domestic basins has been 87.37 MTOE (including 4.39

MTOE from ONGC share in joint ventures (JVs)). Initial in place reserve

accretion in domestic basins was 273.42 MTOE including 22.82 MTOE from

ONGC share in JVs.

Reserve Replacement Ratio (RRR)

Reserve Replacement Ratio i.e. the ratio of reserve accretion to the production

of ONGC in its domestic oil fields in this fiscal has been quite impressive at

1.74 for 3P reserves; again the highest in last two decades. This is 5th

consecutive ONGC maintain RRR of more than 1 against global feature of

lower than 1 registered by large number of oil companies.

Oil & gas Production levels maintained

ONGC has maintained oil and gas production levels despite global trend ofdeclining production from matured oil fields. During FY10, the combine oil

and gas production of ONGCs share in PSC-JVs, was 60.93 MTOE;

marginally lower as compared to 61.23 MTOE in FY09. Production from

overseas fields registered 8.87 MTOE; the highest ever.

Largest oil and gas producer in the country


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Oil and gas production from domestic fields, including ONGCs share in PSC

JVs has been 52.06 MTOE during FY10 against 52.45 MTOE during FY09.

ONGC accounted for 79% of Indias crude oil and 54% of natural gas

production during FY10.

Highest-ever production from overseas assets ONGC Videsh Limited

(OVL) , the flagship wholly owned subsidiary for overseas operations has now

footprints across 15 countries with 39 projects Since its first hydrocarbon

revenue from overseas in 200203 from Vietnam, this year OVL registered

highest-ever production of 8.87 MTOE of oil and gas.

ONGC bags highest number of blocks in NELP-VIII

In NELP-VIII bid round, ONGC in partnership with its consortia members,

submitted the bids for 25 exploration blocks and won 17 of these. In the eight

NELP round which have been rolled out so far, ONGC has won 50% of the

blocks i.e. 121 out of 242blocks awarded by Govt. of India. ONGC now hold 80

NELP blocks (70 as operator)and 62 nomination blocks.

Alternate sources of energy

%! MW Wind power farms set up near Bhuj in Gujrat with an investment of

rs3,080 million in September, 2009 is already is already operational. The

electricity generated is wheeled through Gujarat state electricity grid for captive

consumption by ONGC at Ankleshar, Ahmedabad, Mehsana and vadodara

ONGC plans to setting up 102MW wind farm in Rajasthan.

ONGC Energy Centre set up for holistic research for new and alternate energy

sources has been pursuing a number of new projects like-thermo-chemical

generation of hydrogen, bioconversion of coal/ oil to methane gas, Uranium

exploration, Solid state lighting and Solar PV Energy Farm.

Corporate Social Responsibility (CSR)

ONGC has earmarked 2% of net profit fir various CSR projects. A dedicated

group at the corporate level with regional support oversees the CSR project

implementation. Some of the major schemes in the policy includes;

Education including vocational courses.


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Health care

Entrepreneurship (self help and lively hood generation) schemes.

Infrastructure support near our operational areas.

Environment protection, Ecological conservation, promotion.

Womens empowerment, girl child development, gender sensitive

projects.

Water management including ground water recharge.

Global rankings

No. 1 E & P company in the world among leading global energy majors

as per plats 2010.

No. 24 in PFC ENERGY 50 Ranked 24th

among the global publicity-listed energy companies as per PFC Energy50 list (January, 2010).

Finance Asia ranks ONGC no. 1 among Indian blue chips. Ranked

number 1 Top Blue Chip of the India in the Finance Asia 100 list for

2009 with the highest aggregate net profit(before exceptional) over the

period 2006-2008.

ONGC ranked at 155th position in Forbes Global 2000 list for 2010.

National rankings

ONGC ranked at second position in FE500 list 2010.

Business today Ranks ONGC as best company to work for in core sector.

AWARDS

OISD Awards

ONGC and MRPL have won the following six Oil Industry Safety Awards for

the year 2008-2009, instituted by Oil Industry Safety Directorate (DISD),

MoP&NG. Cauvery Asset has been declared as winner in the category Oil &

Gas Assets (Onshore) on safety standards.


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Heera Processing plant has been adjudged as the best offshore production

Platform under PSUs category on safety standards.

Sagar Shakti has been adjudged as the best offshore drilling rig, under

PSU category on safety standards.

MRPL has been ranked number two in Refineries category.

MRPL has also been rated as the most safe refinery in last three years.

ONGCs Rajahmundry Asset has been rated as the most safe Onshore Oil

& Gas Asset in last three years.

ONGCian Shri Supriyo Chowdhury, Chief Engineer (Drilling), Assam

Asset has been selected for a cash award for his valuable contribution in

the area of safety.

Dainik Bhaskar India Pride Awards for Excellence

ONGC bagged the coveted Gold Award in the CSR category of thr Dainik

Bhaskar India Pride Awards for Excellence in PSUs instituted by Dainik

Bhaskar Group (October, 2010).

ONGC bags Best Overall Performance Award for oil and gas conservation

programmes

ONGC bagged the Best Overall Performance Award instituted by Petroleum

Conservation Research Association (PCRA) amongst the upstream sector Oil

companies for the oil nad gas conservation programmes during the year 2009

(January, 2010).

ONGC bags 5th

BML Munjal Award for excellence in Learning &

Development

ONGC clinched 5th

BML Munjal Award for excellence in Learning &

Development in Public sector category, instituted in the name of Dr. Brijmohan

Lall Munjal (BML), Chairman, Hero Group (March, 2010).


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DSIG Award to ONGC

ONGC clinched two DSIG-PSU awards 2010, one for excellent overall

Performance in category of Heavy Weights and the other for Highest Market

Capitalisation amongst PSUs in the category of Wealth Builders (April, 2010).

ONGC gets Amity Leadership for Business Excellence for leveraging IT

ONGC has been awarded Amity Leadership for Business Excellence for

leveraging IT in Oil & Gas Industry instituted by the Amity University

(January, 2010).

Golden Peacock award for corporate Governance

ONGC has been conferred with Golden Peacock Award for Excellence in

Corporate Governance for 2009 instituted by the World Council of Corporate

Governance, London (October, 2009)

Hazira Plant bags commendation at CII-ITC Sustainability Awards 2009

ONGC, Hazira Plant received Commendation for Strong Commitment among

independent units for the year 2009 at the CII-ITC Sustainability Awards

(November, 2009).


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ONGC in Rajasthan

The forward base office of ONGC is located at Jodhpur. In Rajasthan ONGC is

exploring gas from Thar Desert of Jaisalmer. The Jaisalmer Basin, Western

Rajasthan is located at the eastern flank of Indus Basin. Presence of huge

volume of sediments with adequate good source reservoir rock combination

marks this basin prospective for hydrocarbon exploration. A number of

significant oil and gas fields have been discovered in the Indus basin across our

frontiers. However, such discoveries are relatively few in numbers do not

commensurately match with the vast prospective basinal area for exploration.

Accordingly, ONGC limited exploration for hydrocarbons in Rajasthan since its

inception in 1956. However, exploratory inputs had been rather limited due to

various logistic problems and also due to the lack of major discovery in this

basin except two gas fields at Manhera Tibba and Ghotaru. Nevertheless

interception of recent seismic data acquired through in house and outside

agencies have resulted in identification of a number of structural prospects. No

discovery has been made since 1983. Till end of 1989 indication of oil have

been found in few wells but commercial oil strike has remained elusive. A gas

collection station (GCS) has been established in Gamnewala (around 100 k.m.

away from Jaisalmer) and the gas collected here is supplied to RVVNL

(Rajasthan Vidyut Vitaran Nigam Limited) Ramgarh for running turbine to

produce electricity.

Since the year 2002 ONGC has struck gas at Cinnewala field which is good in

terms of quality and quantity of hydrocarbons and may hopefully usher in a new

era for ONGC in Rajasthan.


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WELL PLANNING

Well planning is perhaps the most demanding aspect of drilling engineering. It

requires the integration of engineering principles, corporate or personal

philosophies, and experience factors. Although well planning methods and

practices may vary within the drilling industry, the end result should be a safely

drilled, minimum-cost hole that satisfies the reservoir engineer's requirements

for oil and gas production.

Well Planning is defined as those, primarily engineering activities, which follow

on from the identification of a subsurface target for a well (exploration,appraisal, or development well) until the completion of that well. This includes:

Definition of well objectives

Planning of the well trajectory

Selection of drilling hardware (bits, tubulars, mud, etc.)

Planning of casing points

Logging objectives and selection of logging tools (MWD, LWD, wirelinelogs)

Test program and decision criteria for testing Completion program and criteria for completion

Well Planning in context of platform planning (i.e., planning a group of wells

from a platform or pad at one time to allow engineering and economic

optimization of the entire platform). This ties to entire field development

planning (for a given set of targets in a new field, optimize the number andlocations of platforms)

Well Planning Objective

The objective of well planning is to formulate a program from many variables

for drilling a well that has the following characteristics:

Safety

Minimum cost

Usable

Unfortunately, it is not always possible to accomplish these objectives on each

well due to constraints based on items such as geology and drilling equipment,

i.e., temperature, casing limitations, hole sizing, or budget.


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WELL PLANNING


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Safety: Safety should be the highest priority in well planning. Personnel

considerations must be placed above all other aspects of the plan. In some cases,

the plan must be altered during the course of drilling the well when unforeseen

drilling problems endanger the crew. Failure to stress crew safety has resulted in

loss of life and burned or permanently crippled individuals.

The second priority involves the safety of the well. The well plan must be

designed to minimize the risk of blowouts and other factors that could createproblems. This design requirement must be adhered to vigorously in all aspects

of the plan.

Minimum Cost. A valid objective of the well planning process is to minimize

the cost of the well without jeopardizing the safety aspects.

In most cases, costs can be reduced to a certain level as additional effort is

given to the planning (Fig. 1-1). It is not noble to build "steel monuments" in the

name of safety if the additional expense is not required. On the other hand,monies should be spent as necessary to develop a safe system.

Usable Holes. Drilling a hole to the target depth is not completely satisfactory if

the final well configuration is not usable. In this case, the term usable implies

the following

The hole diameter is sufficiently large so an adequate completion can

The hole or producing formation is not irreparably damaged.

Fig.1. Well costs can be reduced dramatically if proper well planning is

implemented


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Classification of Well Types

The drilling engineer is required to plan a variety of well types, including

the following:

Well Type Characteristics

Wildcat

Exploratory

Step-out

Infill

Re-entry

Not known (or little) geological foundation

for site selection.

Site based on seismic data, satellite surveys,

etc.; no known drilling data in the

prospective horizon.

Delineates the reservoir's boundaries; drilled

after the exploratory discovery(s); site

location usually based on seismic data.

Drills the known productive portions of the

reservoir; site selection usually based on

patterns, drainage radius, etc.

Existing well re entered to deepen, side track,

rework, or recomplete; various amounts of

planning required, depending on purpose ofre-entry

Overview of the Planning Process

Well planning is an orderly process. It requires that some aspects of the plan be

developed before designing other items. For example, the mud density plan

must be developed before the casing program since mud weights have an impact

on pipe requirements. Fig. 1-2 illustrates a commonly used flow path for a well

plan.

Bit programming can be done at any time in the plan after the historical data

have been analyzed. The bit program is usually based on the drilling parameters

from offset wells. However, bit selection can be affected by the rimed plan, i.e.,

the performance of PCD bits in oil muds. In addition, bit sizing may be

controlled by casing drift diameter requirements. Casing and tubing should be

considered as an integral design. This fact is particularly valid for production

casing. A design criteria for tubing is the drift diameter of the production

casing, whereas the production casing can be affected adversely by the packer-


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to-tubing forces created by the tubing's tendencies for movement.

Unfortunately, these calculations are complex and often neglected.

The completion plan must be visualized reasonably early in the process. Its

primary effect is on the size of casing and tubing to be used if oversized tubing

or packers are required. In addition, the plan can require the use of high strengthtubing or unusually long seal assemblies in certain situations.

Activities before starting drilling operation

Activities undertaken prior to start of drilling operation can be broken down into

the following:

1. Release of location.2. Survey of surface/subsea location. Sometimes the cost can be reduced by

a small change in surface location.

3. Civil works and foundation for onshore drill site and soil coring/sea bedsurvey in case of offshore well.

4. Preparation of Geo-technical order.5. Preparation of complete well plan/programme.6. Preparation of bill of material and initiation of purchase procedure, if

required.

7. Procedures from obtaining sanction for purchase to receipt of material.8. Rig allocation and its shifting to the new location.

GEO TECHNICAL ORDER

The various input data are thoroughly analysed and the geo technical order is

prepared which provides broad guidelines for drilling of well.

G.T.O. furnishes the following details:

1. General data like well name, well no., area, location, water depth,elevation, well type, category, objectives of well, etc.

2. Geological data, which consists of following details depth, age,

formation, oil/gas shows, electro logging, etc.

3. Mud parameters consisting of mud type, specific gravity, viscosity, pH,

percentage of sand, etc.


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4. Drilling data including casing policy and rise of cement, drilling type,

type & size of bits, no. of bits expected, RPM of rotary, etc.

5. Remarks, if any.

CASING

Importance of casing :

To prevent weak formation from collapsing and causing caving of thehole.

Serving as a high strength flow conduit to surface for both drilling andproduction fluids.

Protecting fresh water bearing formation getting contaminated fromdrilling and production fluids.

Provide suitable support for wellhead equipment, tubing and subsurfaceequipment.

Provide safe passage for running wire line equipment. Allowing isolated communication with selective perforated formation of

interest.

Types of Casing and TubingDrilling environments often require several casing strings in order to reach the

total desired depth. Someof the strings are as follows:

Drive or structural conductor

Surface

Intermediate (also known as protection pipe) liners

Production (also known as an oil string)

Tubing (flow string)

Fig shows the relationship of some of these casing strings. In addition, the

illustration shows some of the problems and drilling hazards that the strings are

designed to control.

All wells will not use each type of casing. The conditions to be encountered in

each well must be analyzed to detennine the types and amount of pipe necessary

to drill it. The general functions of all casing strings are as follows:


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segregate and isolate various formations to minimize drilling problems ormaximize production

furnish a stable well with a known diameter through which future drillingand completion operations can be executed

provide a secure means to which pressure control equipment can beattached

Drive Pipe or Conductor Casing. The first string run or placed in the well is

usually the drive pipe, or conductor casing. The normal depths range from 100-

300 ft. In soft-rock areas such as southern Louisiana or most offshore

environments, the pipe is hammered into the ground with a large diesel hammer.

Hard-rock areas require that a large-diameter, shallow hole be drilled before

running and cementing the pipe. Conductor casing can be as elaborate as heavy

wall steel pipe or as simple as a few old oil drums tacked together.

A primary purpose of this string of pipe is to provide a fluid conduit from the bit

to the surface. Very shallow fonnations tend to wash out severely and must be

protected with pipe. In addition, most shallow fonnations exhibit some type of

lost circulation problem that must be minimized. An additional function of the

pipe is to minimize hole caving problems.

Gravel beds and unconsolidated rock will continue to fall into the well if notstabilized with casing. Typically, the operator is required to drill through these

zones by pumping viscous muds at high rates.

Structural Casing. Occasionally, drilling conditions will require that an

additional string of casing be run between the drive pipe and surface casing.

Typical depths range from 600-1,000 ft. Purposes for the pipe include solving

additional lost circulation or hole caving problems and minimizing kick

problems from shallow gas zones.

Surface Casing. Many purposes exist for running surface casing, including the

following:

cover freshwater sands

maintain hole integrity by preventing caving minimize lost circulationinto shallow, permeable zones

cover weak zones that are incompetent to control kick-imposed pressures

provide a means for attaching the blowout preventers .support the weight

of all casing strings (except liners) run below the surface pipe.


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Intermediate Casing. The primary applications of intermediate casing involve

abnormally high formation pressures. Since higher mud weights are required to

control these pressures, the shallower weak formations must be protected to

prevent lost circulation or stuck pipe. Occasionally, intermediate pipe is used to

isolate salt zones or zones that cause hole problems, such as heaving andsloughing shales.

Liners. Drilling liners are used for the same purpose as intermediate casing.Instead of running the pipe to the surface, an abbreviated string is used from the

bottom of the hole to a shallower depth inside the intermediate pipe. Usually the

overlap between the two strings is 300-500 ft. Inthis case, the intermediate pipe

is exposed to the same drilling considerations as the liner.

Drilling (and production) liners are used frequently as a cost-effective method

to attain pressure or fracture gradient control without the expense of running a

string to the surface. When a liner is used, the upper exposed casing, usually

intermediate pipe, must be evaluated with respect to burst and collapsepressures for drilling the open hole below the liner. Remember that a full string

of casing can be run to the surface instead of a liner if required, i.e., two

intermediate strings.

Production Casing. The production casing is often called the oil string.

The pipe may be set at a depth slightly above, midway through, or below the


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pay zone. The pipe has the following purposes:

isolate the producing zone from the other formations

provide a work shaft of a known diameter to the pay zone

protect the production tubing equipment

Tie-back String. The drilling liner is often used as part of the production

casing rather than running an additional full string of pipe from the surface to

the producing zone. The liner is tied-back or connected to the surface by

running the amount of pipe required to connect to the liner top. This procedure

is particularly common when

1) Producing hydrocarbons are behind the liner and

2) The deeper section is not commercial.

Setting Depth Design Procedures

'Casing seat depths are directly affected by geological conditions. In some

cases, the prime criterion for selecting casing seats is to cover exposed, severe


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lost circulation zones. In others, the seat selection may be based on differential

sticking problems, perhaps resulting from pressure depletion in a field. In deep

wells, however, the primary consideration is usually based on controlling

abnormal formation pressures and preventing their exposure to weaker shallow

zones. The design criteria of controlling formation pressures generally appliestomost drilling areas.

Selecting casing seats for pressure control purposes starts with knowing

geological conditions such as formation pressures and fracture gradients. Thisinformation is generally available within an acceptable degree of accuracy. Pre-

spud calculations and. the actual drilling conditions will determine the exact

locations for each casing seat. The principle used to determine setting depth

selection can be adequately described by the adage, "hindsight is 20-20." The

initial step is to determine the formation pressures and fracture gradients that

will be penetrated in the well. After these have been established, the operator

must design a casing program based on the assumption that he already knows

the behavior of the well even before it is drilled.This principle is used extensively for infill drilling where the known conditions

dictate the casing program. Using these guidelines, the operator can select the

most effective casing program that will meet the necessary pressure

requirements and minimize the casing cost.

WELLHEAD SELECTION

Having completed the casing design, we have all the information required to

allow us to select a wellhead.

A wellhead is a general term used to describe the component at the surface of

an oil or gas well that provides the structural and pressure-containing interface

for the drilling and production equipment.

The primary purpose of a wellhead is to provide the suspension point and

pressure seals for the casing strings that run from the bottom of the hole sections

to the surface pressure control equipment.While drilling the oil well, surface

pressure control is provided by a blowout preventer (BOP). If the pressure is not

contained during drilling operations by the column of drilling fluid, casings,

wellhead, and BOP, a well blowout could occur.

Once the well has been drilled, it is completedto provide an interface with the

reservoir rock and a tubular conduit for the well fluids. The surface pressure


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control is provided by a christmas tree, which is installed on top of the

wellhead, with isolation valves and choke equipment to control the flow of well

fluids during production.

Wellheads are typically welded onto the first string of casing, which has beencemented in place during drilling operations, to form an integral structure of the

well. In exploration wells that are later abandoned, the wellhead may be

recovered for refurbishment and re-use.

Offshore, where a wellhead is located on the production platform it is called

a surface wellhead, and if located beneath the water then it is referred to as

asubsea wellhead or mudline wellhead.

The wellhead must of correct pressure rating, designed for the desired

service like H2S and be capable of accommodating all designed and

contingent casing strings.

Components:

The primary components of a wellhead system are:

casing head

casing spools

casing hangers packoffs (isolation) seals

bowl protectors / wear bushings

test plugs

mudline suspension systems

tubing heads

tubing hangers

tubing head adapters

Having selected a well head, its specifications should be included in the Drilling

Programme along with a sectional view of its components stack up.


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BOP REQUIREMENTWhen primary control of the well has been lost due to insufficient mudhydrostatic pressure, it becomes necessary to seal the well to prevent an

uncontrolled flow, or blowout, of formation fluids. The equipment that seals thewell is the blowout preventer (BOP).

Types of Blowout Preventers

Annular Blowout Preventers Annular Preventer Ram Preventer

Drill pipe Blowout Preventers

Annular (Spherical) Preventers

The first preventer normally closed when Shut in procedures are initiated is the

annular preventer. The four basic segments of the annular preventer are the

head, body, piston, and steel-ribbed packing element . When the preventer's

closing mechanism is actuated hydraulic pressure is applied to the piston,causing it to slide upward and force the packing element to extend into the

wellbore around the drillstring. The preventer element is opened by applying

hydraulic pressure in a manner that slides the piston downward and allows thepacking to return to its original position.

Ram Preventers

Unlike the operational manner of the annular preventer, the ram preventers sealthe annulus by forcing two elements to make contact with each other in the

annular area. These elements have rubber packing seals that affect the complete

closure. Other than the sealing mechanism, ram blowout preventers (pipe, blind,

and shear) differ greatly from annular preventers in that each type and size of

ram has one function and cannot be used in a variety of applications.


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Blind rams seal the well if pipe is not in the hole. The element isflatfaced and contains a rubber section. The rams are not designed to

effect a seal when pipe is in the hole, although occasionally the pipe will

be cut if the blind rams are accidentally closed. Precautions should thusbe taken with the blowout preventer control panel to ensure the blind

rams cannot be accidentally closed.

Shear rams are specially designed blind rams. As the word "shear"indicates, this type of ram will seal if pipe is in the hole by shearing, or

cutting, the pipe and sealing the open wellbore.

The requirement of the above mentioned BOPs depends upon the companys

policy and anticipated bottom hole pressures. Surface holes have either no BOP

requirement, or will need to use a diverter.

CEMENTING PROGRAMME

The 3 main factors that must be considered at the planning stage are :

Slurry Design

Casing Accesories Selection

Displacement rate & methods

SLURRY DESIGN:

Cement tests should always be performed on representative samples of cement,

additives and mix water as supplied from the rig. Cement tests are detailed in

API 10, references a & b.

THICKENING TIME:

Thickening time tests are designed to determine the length of time which a

cement slurry remains in a pumpable state under simulated wellbore conditionsof temperature and pressure. The pumpability, or consistency, is measured in

Bearden Consistency units (Bc); each unit being equivalent to the spring

deflection observed with 2080 gm-cm of torque when using the weight-loaded

type calibration device. The measure takes no account of the effect of fluid loss.Thus, thickening times in the wellbore may be reduced if little, or no, fluid loss

control is specified in the slurry design. Results should quote the time to reach

70 Bc - generally considered to be the maximum pumpable consistency.

FLUID-LOSS


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Fluid-loss tests are designed to measure the slurry dehydration during, and

immediately after cement placement. Under simulated wellbore conditions, the

slurry is tested for filtrate loss across a standardised filter press at differential

pressures of 100 psi or 1000 psi. The test duration is 30 minutes and results are

quoted as ml/30 min.

COMPRESSIVE STRENGTH

The measurement of the uniaxial compressive strength of two-inch cubes ofcement provides an indication of the strength development of the cement at

downhole conditions. The slurry samples are cured for 8, 12, 16 and 24 hours at

bottom-hole temperatures and pressures and the results reported in psi. Dynamic

measurements using ultrasonic techniques correlate well with API test results,

but can lead to over-estimation of the strength.

RHEOLOGY

Ensuring that the rheological behaviour of the slurry downhole is similar to thatspecified in the design is essential for effective cement placement. The slurry

viscosity is measured using a rotational viscometer, such as a Fann. The slurry

sample should be conditioned for 20 minutes in an atmospheric consistometer

before measurements are taken. Readings should be taken at ambient conditions

and at BHCT when possible. Measurements should be limited to a maximum

speed of 300 rpm (shear rate 511 1/s). Readings should also be reported at 200,

100, 60, 30, 6 and 3 rpm.

CEMENTING AND CASING HARDWARES

Some or all of the following equipment is used during cementing operations.

1. Guide shoes

2. Float Collars

3. Baskets and Centralisers

4. Cement Plugs5. Multistage Collars

MUD PROGRAMMEThe following information should be collected and used when selecting drilling

fluid or fluids for a particular well. It should be noted that it is common to

utilise two or three different fluid types on a single well.

Pore pressure /fracture gradient plots to establish the minimum / maximum

mud weights to be used on the whole well, see Chapters One and Two for

details.


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Offset well data (drilling completion reports, mud recaps, mud logs etc.) from

similar wells in the area to help establish successful mud systems, problematic

formations, potential hazards, estimated drilling time etc.

Geological plot of the prognosed lithology.

Casing design programme and casing seat depths. The casing schemeeffectively divides the well into separate sections; each hole section may have

similar formation types, similar pore pressure regimes or similar reactivity to

mud. Basic mud properties required for each open hole section before it is cased off.

Restrictions that might be enforced in the area i.e. government legislation in

the area, environmental concerns etc.

Drilling Mud Properties :

MUD WEIGHT OR MUD DENSITY FUNNEL VISCOSITY

PLASTIC VISCOSITY (PV)

YIELD POINT

GEL STRENGTHS

FLUID LOSS AND FILTER CAKE

SOLIDS CONTROL EQUIPMENT

Having decided on the mud system to be used for the well, the mud treatmentequipment available on the rigs should be appraised to check compatibility with

the selected system. The treatment equipment falls into the four main groups:

Shale shakers(60)

Mud cleaners(30)

De-sanders and De-Silters(60-15)

Centrifuge (1-2)

Solids contaminants and gas entrapped in mud can be removed from mud infour 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) and centrifuges.


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BIT AND HYDRAULICS PROGRAMME

Bit selection begins with a thorough examination of bit records from offset

wells data. The best and worst performance and dull bit grading in formations

comparable to the well being designed should be examined, analysed and the

used to determine the characteristics of the best performing drill bits. In

particular attention should be placed on the details such as the premature failure

of bits, reasons drillbits pulled, dull characteristics of inserts: whether the insertswere worn or broken, etc. A drill bit that had broken inserts clearly indicate that

the formation should have been drilled with a much harder drillbit. This detailed

examination will be explained in the next sections of this chapter.

Data required for the correct bit selection include the following:

1. Prognosed lithology column with detailed description of each formation

2. Drilling fluid details

3. Well profile

When drilling directional wells the Directional Contractor should be asked to

provide an assessment of the required BHA changes, motor requirements and

any limitations on bit operating parameters which may impact on the selection

of bits. In addition bit characteristics in terms of walk, build and drop

tendencies will need to be assessed for their impact on the well path.

When using a mud motor in the assembly all tri-cone bits should have a motorbearing system which allows extended use at high motor RPMs or a fixed

cutter bit should be selected.

Due consideration should always be given to the jet system of the bit. When

drilling soft shale sections where the major limitations on ROP is bottom hole

and cutter cleaning, the use of centre jet, extended jets or lateral jet bits should

be considered.

There are 3 types of drilling bits:1. Drag bits2. Roller cone or rock bits3. Diamond bitsa) PDC (Polycrystalline Diamond Compact) bitsb) TSP (Thermally Stable Polycrystalline) bits


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The hydraulics system serves many purposes in the well. Since it is centered

around the mud system, the purposes of mud and hydraulics are often common

to each other .

The hydraulics system has many effects on the well. Therefore, the reasons forgiving attention to hydraulics are abundant. The more common reasons are as

follows:

control subsurface pressures

provide a buoyant effect to the drillstring and casing minimize hole

erosion due to the mud's washing action during movement

remove cuttings from the well, clean the bit, and remove cuttings from

below the bit

increase penetration rate size surface equipment such as pumps

control surge pressures created by lowering pipe into the well

minimize wellbore pressure reductions from swabbing when pulling pipefrom the well

Evaluate pressure increases in the wellbore when circulating the mud.

maintain control of the well during kicks

Quite often, these effects are interrelated, which increases the difficulty in

optimization.

There are two main theories concerning how much hydraulic horsepower should

be expended at the bit to gain maximum cleaning efficiency. The first theory isthe maximum hydraulic horsepower theory, which in practice means expending

2/3rd

of the available HHP at the bit. The alternative theory is the maximum jet

impact theory which in practice means expending around 50% of the available

HHP at the bit.

EVALUATION REQUIREMENTS

In this part of the programme, the evaluation requirements necessary to meet thewell objectives should be formatted as follows:

Drilling log requirements

Mud logging requirements

Coring requirements

MWD requirements

Electric logging requirements

Testing requirements


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LOG INTERPRETATION OBJECTIVES

The objective of log interpretation depends very much on the user.Quantitative analysis of well logs provides the analyst with values for a

variety of primary parameters, such as: porosity water saturation, fluid type (oil/gas/water) lithology permeability From these, many corollary parameters can be derived by integration (and

other means) to arrive at values for:

hydrocarbons-in-place reserves (the recoverable fraction of hydrocarbons in-place) mapping reservoir parameters But not all users of wireline logs have quantitative analysis as their

objective. Many of them are more concerned with the geological andgeophysical aspects. These users are interested in interpretation for:

well-to-well correlation facies analysis regional structural and sedimentary history In quantitative log analysis, the objective is to define the type of reservoir (lithology) its storage capacity (porosity) its hydrocarbon type and content (saturation) its producibility (permeability)

GAMMA RAY LOG

Gamma Rays are high-energy electromagnetic waves which are emittedby atomic nuclei as a form of radiation

Gamma ray log is measurement of natural radioactivity in formationverses depth.

It measures the radiation emitting from naturally occurring U, Th, and K.

It is also known as shale log. GR log reflects shale or clay content. Clean formations have low radioactivity level. Correlation between wells, Determination of bed boundaries, Evaluation of shale content within a formation, Mineral analysis, Depth control for log tie-ins, side-wall coring, or perforating. Particularly useful for defining shale beds when the sp is featureless

GR log can be run in both open and casedhole


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Spontaneous Potential Log (SP)

The spontaneous potential (SP) curve records the naturally occurringelectrical potential (voltage) produced by the interaction of formation

connate water, conductive drilling fluid, and shale The SP curve reflects a difference in the electrical potential between a

movable electrode in the borehole and a fixed reference electrode at the

surface Though the SP is used primarily as a lithology indicator and as a

correlation tool, it has other uses as well:

permeability indicator, shale volume indicator porosity indicator, and measurement of Rw (hence formation water salinity).

Neutron Logging

The Neutron Log is primarily used to evaluate formation porosity, but thefact that it is really just a hydrogen detector should always be kept in

mind

It is used to detect gas in certain situations, exploiting the lower hydrogendensity, or hydrogen index

The Neutron Log can be summarized as the continuous measurement ofthe induced radiation produced by the bombardment of that formationwith a neutron source contained in the logging tool which sources emit

fast neutrons that are eventually slowed by collisions with hydrogen

atoms until they are captured (think of a billiard ball metaphor where the

similar size of the particles is a factor). The capture results in the

emission of a secondary gamma ray; some tools, especially older ones,

detect the capture gamma ray (neutron-gamma log). Other tools detect

intermediate (epithermal) neutrons or slow (thermal) neutrons (bothreferred to as neutron-neutron logs). Modern neutron tools most

commonly count thermal neutrons with an He-3 type detector.

Induction Logs are used in wells that do not use mud or water, but oil-based

drilling fluids or air, which are nonconductive and, therefore, cannot use electric

logs. Induction uses the interaction of magnetism and electricity to determineResistivity.

The Density Log

The formation density log is a porosity log that measures electron density

of a formation


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Dense formations absorb many gamma rays, while low-densityformations absorb fewer. Thus, high-count rates at the detectors indicate

low-density formations, whereas low count rates at the detectors indicate

high-density formations.

Therefore, scattered gamma rays reaching the detector is an indication offormation Density.Scale and units:

The most frequently used scales are a range of 2.0 to 3.0 gm/cc or 1.95 to 2.95gm/cc across two tracks.

A density derived porosity curve is sometimes present in tracks #2 and #3 along

with the bulk density (rb) and correction (Dr) curves. Track #1 contains a

gamma ray log and caliper.

Methods of Well Logging:

Resistivity Log

Basics about the Resistivity:

Resistivity measures the electric properties of the formation, Resistivity is measured as, R in W per m, Resistivity is the inverse of conductivity, Theability to conduct electric current depends upon:

The Volume of water,

The Temperature of the formation, The Salinity of the formation

The Resistivity Log:Resistivity logs measure the ability of rocks to conduct electrical current

and are scaled in units of ohm-meters.

The Usage:

Resistivity logs are electric logs which are used to:

Determine Hydrocarbon versus Water-bearing zones,

Indicate Permeable zones, Determine Resisitivity Porosity.

Acoustic Log

Acoustic tools measure the speed of sound waves in subsurfaceformations. While the acoustic log can be used to determine porosity in

consolidated formations, it is also valuable in other applications, such as:

Indicating lithology (using the ratio of compressional velocity over shear

velocity),


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Determining integrated travel time (an important tool forseismic/wellbore correlation),

Correlation with other wells Detecting fractures and evaluating secondary porosity,

Evaluating cement bonds between casing, and formation, Detecting over-pressure, Determining mechanical properties (in combination with the density log),

and Determining acoustic impedance (in combination with the density log).

WELL COST ESTIMATIONREASONS FOR COSTING

As will be discussed later, there are many elements which comprise the well

cost. These range from rig, casing, people, drilling equipment etc.

The final sheet summarizing the well cost is usually described as the AFE:

Authorisation 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 managerfrom 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.

There are several reasons for producing a well cost, including:

1. Budgetary control2. Economics3. Partners recharging4. Shareholders

The AFE is then used as a document for partners recharging, paying contractors

and an overall control on the well spending.

FACTORS AFFECTING WELL COSTS

Well costs for a single well depend on:

1. Geographical location: land or offshore, country

2. Type of well: exploration or development, HPHT or sour gas well


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3. Drillability

4. Hole depth

5. Well target(s)

6. Profile (vertical/ horizontal /multilateral)

7. Subsurface problems8. Rig costs: land rig, jack-up, semi-submersible or drillship and rating of rig

9. Completion type

10. Knowledge of the area: wildcat, exploration or development

The total well costs for a development drilling programme comprising several

wells depend on:

Rig rate

Well numbers and well type

Total hole depth

Well layout and spacing

Specifications of equipment Target tolerances

Water depth for offshore wells

Elements of well cost:

1. Preparatory2. Manpower3. Services4. Materials5. Project Overheads6. Regional and Headquarter overheads7. Depreciation of rig equipments8. Depreciation of drill pipes


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REFERENCES

www.wikipedia.com

Google Images

Drilling Operations Manual (ONGC)

www.rigzone.com

Drilling Engineering - A Complete Well Planning Approach by Neal J.

Adams

Well Engineering & Construction by Hussain Rabia

release of location and well planning

Documents