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DOWNHOLE DRILLING COMPLICATIONS

AND WELL CONTROL

INSTITUTE OF DRILLING TECHNOLOGY

ONGC DEHRADUN

Supervised by: Submitted by: Er. Kishore Acharya Aditya Keller Executive Engineer (Drilling) Akshay Bisht IDT Operations Monitoring Rishabh Sharma Dehradun

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CERTIFICATE

I hereby certify that the work which is being presented in the report

entitled “Downhole Drilling Complications and Well Control” is in the

partial fulfillment for the award of the certificate of the Summer

Training, submitted to OMG, IDT by Aditya Mohan Keller, Akshay Bisht

and Rishabh Sharma, is an authentic record of their own work carried

out under my supervision.

I wish them all the best for their future endeavors.

DATE: Er. Kishore Acharya EE (Drilling)

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ACKNOWLEDGEMENT

We are highly grateful to Er. KISHORE ACHARYA, Executive Engineer

(DRILLING) Institute Of Drilling Technology, OIL AND NATURAL GAS

CORPORATION LTD., DEHRADUN for providing us the opportunity to work

on the Project .We are also grateful to SH. SHASHIKANT SINGH , DGM

(DRILLING ) Summer training coordinator- IDT, ONGC, DEHRADUN.

We are really thankful to all the members of IDT who were always there to help us

out in the time of any difficulty, and without their outstanding efforts we were not

able to finish our project .

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CONTENTS

PAGE

HISTORY OF ONGC and IDT HISTORY OF ONGC…………………………… 4

HISTORY OF IDT………………………………. 6 INTRODUCTION TO DRILLING

GEO TECHNICAL ORDER(GTO)… 7-8

DRILLING RIG BUILDING…………. 9-10

LOWERING OF CASING…………… 11-13

COMPLETING THE WELL…………. 14

CASING TEST………………………….. 15 DOWNHOLE COMPLICATIONS

STUCK UP……………………. 16-25

STRING FAILURE…………. 26-27

BIT FAILURE……………….. 28

CASING FAILURE………… 28 FISHING………………………………………………….. 29-32 WELL CONTROL

INTRODUCTION…………………………….. 33-35

WARNINGS OF KICK………………………. 36-38

METHODS OF KILLING A WELL……….. 39-44

BOP……………………………………………….. 45-50

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History of ONGC

Since its inception, ONGC has been instrumental in transforming the country's

limited upstream sector into a large viable playing field, with its activities spread

throughout India and significantly in overseas territories. In the inland areas, ONGC

not only found new resources in Assam but also established new oil province in

Cambay basin (Gujarat), while adding new petroliferous areas in the Assam-Arakan

Fold Belt and East coast basins (both onshore and offshore). ONGC went offshore

in early 70's and discovered a giant oil field in the form of Bombay High, now known

as Mumbai High. This discovery, along with subsequent discoveries of huge oil and

gas fields in Western offshore changed the oil scenario of the country. Subsequently,

over 5 billion tons of hydrocarbons, which were present in the country, were

discovered. The most important contribution of ONGC, however, is its self-reliance

and development of core competence in E&P activities at a globally competitive

level.

Before the independence of India, the Assam Oil Company in the north-eastern and

Attock Oil Company in north-western part of the undivided India were the only oil

producing companies, with minimal exploration input. The major part of Indian

sedimentary basins was deemed to be unfit for development of oil and gas resources.

After independence, the Central Government of India realized the importance of oil

and gas for rapid industrial development and its strategic role in defense.

Consequently, while framing the Industrial Policy Statement of 1948, the

development of petroleum industry in the country was considered to be of utmost

necessity.

Until 1955, private oil companies mainly carried out exploration of hydrocarbon

resources of India. In Assam, the Assam Oil Company was producing oil

at Digboi (discovered in 1889) and Oil India Ltd. (a 50% joint venture between

Government of India and Burmah Oil Company) was engaged in developing two

newly discovered large fields Naharkatiya and Moraan in Assam. In West Bengal,

the Indo-Stanvac Petroleum project (a joint venture between Government of

India and Standard Vacuum Oil Company of USA) was engaged in exploration

work. The vast sedimentary tract in other parts of India and adjoining offshore

remained largely unexplored.

In 1955, Government of India decided to develop the oil and natural gas resources

in the various regions of the country as part of the Public Sector development. With

this objective, an Oil and Natural Gas Directorate was set up towards the end of

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1955, as a subordinate office under the then Ministry of Natural Resources and

Scientific Research. The department was constituted with a nucleus of geoscientists

from the Geological Survey of India.

A delegation under the leadership of the Minister of Natural Resources visited

several European countries to study the status of oil industry in those countries and

to facilitate the training of Indian professionals for exploring potential oil and gas

reserves. Experts from Romania, the Soviet Union, the United States and West

Germany subsequently visited India and helped the government with their

expertise. Soviet experts later drew up a detailed plan

for geological and geophysical surveys and drilling operations to be carried out in

the 2nd Five Year Plan (1956-61).

In April 1956, the Government of India adopted the Industrial Policy Resolution,

which placed Mineral Oil Industry among the schedule 'A' industries, the future

development of which was to be the sole and exclusive responsibility of the state.

Soon, after the formation of the Oil and Natural Gas Directorate, it became apparent

that it would not be possible for the Directorate with its limited financial and

administrative powers as subordinate office of the Government, to function

efficiently. So in August, 1956, the Directorate was raised to the status of a

commission with enhanced powers, although it continued to be under the

government. In October 1959, the Commission was converted into a statutory body

by an act of the Indian Parliament, which enhanced powers of the commission

further. The main functions of the Oil and Natural Gas Commission subject to the

provisions of the Act, were "to plan, promote, organize and implement programs for

development of Petroleum Resources and the production and sale of petroleum and

petroleum products produced by it, and to perform such other functions as the

Central Government may, from time to time, assign to it. The act further outlined

the activities and steps to be taken by ONGC in fulfilling its mandate.

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History of IDT

The Institute of Drilling Technology (IDT) was set up in 1978 at Dehradun. Located

in the picturesque valley of Doon between the green Shivaliks and the lower

Himalayas, it is engaged in relentless effort in R&D and has rendered excellent

services in the area of oil and gas well drilling technology. Over the years, the

Institute has emerged as a premier R&D centre in South East Asia, capable of

providing advance technical knowledge through training and offering plausible

solution to field problems. Institute of Drilling Technology (IDT) provides its

techno-economic expertise & solutions to various field problems faced by

various services of ONGC with the ultimate objective to promote cost effective

E&P activities of the company. Besides R&D, the institute also imparts Training &

disseminates the knowledge required for developing a qualified and efficient

workforce capable of delivering, through its Drilling Technology and Well Control

Schools.

The Institute with highly qualified and experienced scientists and engineers, carries

out applied research in all facets of drilling related activities to achieve technical

excellence in R&D efforts and assimilation of emerging technologies.

The integrated HRD division imparts training to participants from both national and

international oil companies in various aspects of oil well drilling technologies. The

renowned Well Control School at IDT has been accredited by International Well

Control Forum, The Netherlands, International Alliance for Well Control, the

Netherlands, and also from International Association of Drilling Contractors,

USA.

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GEO TECHNICAL ORDER (GTO)

This programming of the well which covers all geological and other technical data

and serves as guide during the course of drilling is termed as “geotechnical order”.

The various input data are thoroughly analyzed and Geo technical order (GTO) is

prepared which provides broad guidelines for drilling of the well.

GTO furnishes the following details

1. General data like well name, well number, area, location, water depth, elevation,

well type, category, objective of the well etc.

2. Geological data consists of following details:

Depth

Age

Formation

Lithology

Interval of coring

Electro logging

Collection of cuttings

Dip Angle

Oil/gas shows

Formation pressure

Formation temperature

Mud loss/caving zones

3. Mud parameters consists of

Type of mud

Specific gravity

Viscosity

pH

Percentage of sand

Filtration loss

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4. Drilling data includes

Casing policy and rise of cement

Type of drilling

Type and size of bit

Number of bits expected

Weight on bit

Round per minute of rotary

Stand pipe pressure

Pump discharge

Bit nozzle details

Drilling time

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DRILLING RIG BUILDING

Based on the type of rig the drill site for the future well must be prepared for

proper placement of equipment. The land around the well site is cleared,

graded & leveled. A cellar pit is made along with rig specific foundation. For

all other auxiliary equipment placement leveled foundation strips are made. If

necessary local roads and appropriate areas around the rig are surfaced to

facilitate transportation of rig equipments.

Drilling rig equipment can be divided in 2 systems:

1. Mast and sub-structure

2. Power system

a. A.C-D.C

b. D.C-D.C (obsolete now)

Most land rigs come under two categories

a. Carrier mounted rigs

These are also called mobile rigs. In which rig is mounted on wheeled carrier.

This carrier can be driven to the well site with all necessary hoisting carrier.

This carrier can be driven to the well site with all necessary hoisting

equipment, engines and special telescopic mast as complete on truck unit.

These rigs are for shallower depth wells.

b. High Floor Mast and Sub Structure

These are higher capacity rigs. In this rig components are transported to new

location with the help of trucks and heavy duty trailers.

Electrical Rigs are of two types

1. Sky top/Brewster design-High floor modular Rig :

This design is an improved modular rig having elevatable drill floor,

coupled to low structure, through parallel spaced links. The base of the

mast is pivotally supported from the derrick floor, rather than base.

Various elevating systems are provided for raising the derrick floor

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through line and sheave arrangement. Steps involved in raising of sky

top rig:-

i. Rear floor raising along with draw-works.

ii. Front Floor raising.

iii. Spreading of A-frame and Mast erection.

2. Branham Industries Universal Cantilever Swing lift mast :

This design is an improved version having self-elevating sub structure.

Draw-works and surrounding floor are raised to drilling position by use

of draw-works power and mast raising line, no other rigging or wire

line required. Mast raising lines need only be moved from A- frame

sheaves to the sheaves on draw-works elevator to complete rigging for

erection. Steps involved in rising of erection. Steps involved in raising

of Branham type rig:-

i. A-frame erection & Raising of Mast with set back parallelogram in

place.

ii. Raising of rear floor with draw-works.

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LOWERING OF CASING INSTALLATING THE 30” CONDUCTOR

The first stage in the operation is to drive a large diameter pipe to a depth of

approximately 100ft below ground level using a truck mounted pile-driver. This pipe

(usually called casing or in the case of the first pipe installed , the conductor) is

installed to prevent the unconsolidated surface formations from collapsing whilst

drilling deeper. Once this conductor which typically has an outside diameter (O.D)

of 30” is in place the full sized drilling rig is brought onto the site and set up over

the conductor, and preparations are made for the next stage of the operation.

DRILLING AND CASING THE 26” HOLE

The first hole section is drilled with a drill bit, which has a smaller diameter

than the inner diameter (I.D) of the conductor. Since the I.D of the conductor is

approximately 28”, 26” diameter bit is generally used for this hole section. This 26”

will be drilled down through the unconsolidated formations, near surface, to

approximately 2000’.

Whilst drilling the 26” hole, drilling fluid(mud) is circulated down the drill pipe

across the face of the drill bit and up the annulus between the drill pipe and the bore

hole carrying drilled cuttings from the face of the bit to surface. At surface the

cuttings are removed from the mud before it is circulated back down the drill pipe

to collect more cuttings.

When the drill bit reaches approximately 2000’ the drill string is pulled out of the

hole and another string of pipe (surface casing) is run into the hole. This casing

which is generally 20” O.D is delivered to the rig in 40ft lengths (joints) with

threaded connections at either end of each joint. The casing is lowered into the hole,

joint by joint until it reaches the bottom of the hole. Cement slurry is than pumped

into the annular space between the casing and the borehole. This cement sheath acts

as a seal between the casing and the borehole, preventing cavings from falling down

through the annular space between the casing and hole, into the subsequent hole/or

fluids flowing from the next hole section up into this annular space.

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DRILLING AND CASING THE 17 1/2" HOLE

Once the cement has set hard, a large spool called a wellhead housing is

attached to the top of the 20” casing. This wellhead housing is used to support the

weight of subsequent casing string and the annular valves known as the Blowout

prevention (BOP) stack which must be placed on top of the casing before the next

hole section is drilled.

Since it is possible that formations containing fluids under high pressure will be

encountered whilst drilling the next (17 1/2”) hole section a set of valves known as

a Blowout prevention (BOP) stack is generally fitted to the wellhead before the 17

1/2" hole section is started. If high pressure fluids are encountered they will displace

drilling mud, if the BOP stack were not in place, would flow in an uncontrolled

manner to surface. This uncontrolled flow of hydrocarbons is termed a Blowout .

The BOP valves are designed to close around drill pipe, sealing off the annular space

between the drill pipe and the casing. These BOPS have a large I.D so that all of the

necessary drilling tools can be run in hole.

When the BOP’s have been installed and pressure tested a 17 1/2” hole is drilled

down to 6000ft. Once this depth has been reached the troublesome formations in the

17 1/2” hole are isolated behind another string of casing( 13 5/8” intermediate

casing). This casing is run into the hole in the same way as the 20” casing and is

supported by the 20” wellhead housing whilst it is cemented in place.

When the cement has set hard the BOP stack is removed and a wellhead spool is

mounted on top of the wellhead housing. The wellhead spool performs the same

function as wellhead housing except that the wellhead spool has a spool connection

on its upper and lower end whereas the wellhead housing has threaded or welded

connection on its lower end and a spool connection on its upper end. This wellhead

spool supports the weight of the next string of casing and the BOP stack which is

required for the next hole section.

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DRILLING AND CASING THE 12 1/4" HOLE

When the BOP has been reinstalled and pressure tested a 12 1/4” hole is drilled

through the oil bearing reservoir. Whilst drilling through this formation oil will be

visible on the cuttings being bought to surface by the drilling fluid. If gas is present

in the formation it will also be brought to surface by the drilling fluid and detected

by gas detector place above the mud flowline connected to the top of the BOP stack.

If oil or gas is detected the formation will be evaluated more fully.

The drillstring is pulled out and tools which can measure for instance: the electrical

resistance of the fluids in the rock(indicating the presence of water or hydrocarbons);

the bulk density of the rock(indicating the porosity of the rock); or the natural

radioactive emissions from the rock(indicating the presence of non-porous shales or

porous sands) are run in hole. These tools are run on conductive cable called electric

wireline, so that the measurements can be transmitted and plotted (against depth)

almost immediately at surface. These plots are called Petrophysical logs and the

tools are therefore called wireline logging tools.

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COMPLETING THE WELL

If the well is to be used for long term production, equipment which will allow the

controlled flow of the hydrocarbons must be installed in the well. In most cases the

first step in this operation is to run and cement production casing (9 5/8” O.D) across

the oil producing zone. A string of pipe known as tubing (4 1/2” O.D) through which

the hydrocarbons will flow is then run inside this casing string. The production

tubing, unlike the production casing, can be pulled from the well if it develops a leak

or corrodes. The annulus between the production casing and the production tubing

is sealed off by a device known as a packer. This device is run on the bottom of the

tubing and is set in place by hydraulic pressure or mechanical manipulation of the

tubing string.

When the packer is positioned just above the pay zone its rubber seals are expanded

to seal off the annulus between the tubing and the 9 5/8” casing. The BOP’s are then

removed and a set of valves (Christmas Tree) is installed on the top of the wellhead.

The Xmas tress is used to control the flow of oil once it reaches the surface. To

initiate production, the production casing is “perforated” by explosive charges run

down the tubing on wireline and positioned adjacent to the pay zone. Holes are then

shot through the casing and cement into the formation. The hydrocarbons flow into

the wellbore and up the tubing to the surface.

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CASING TEST

PROCEDURE

After testing of BOPs and choke and kill manifold, the following sequence of

operation are followed to test casing.

1. Run in drill string and bit, up to the top of the cement.

2. Break circulation and test casings to 200 psi greater than the anticipated shoe test.

Do not exceed 80% of the burst rating of the casing.

Test duration is 15 minutes. It is considered positive if drop in pressure is more than

5%

INTERMEDIATE CASING TEST

After testing of BOP , choke and kill manifold etc testing of intermediate casing is

to be carried out as follows:

1. Run in drill string and bit up to the top of the cement.

2. Circulate and condition the mud. Drill/clear up to top of float collar, Circulate for

hole cleaning.

3. Test the casing, test pressure should not exceed minimum of the following.

80% of the internal yield pressure of the weakest section of the casing

lowered.

Maximum allowable casing head pressure.

NOTE: If casing shoe is drilled out, test pressure should not exceed the formation

fracture pressure at the shoe. Test duration is 15 minutes.

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DOWNHOLE COMPLICATIONS

Complication is a problem in the well bore that prevents safe drilling, logging, casing

lowering, cementation, production testing and completion of a well.

Common types of drilling complications are:

1. Stuck up

2. String failure.

3. Bit failure.

4. Casing failure

.

1) STUCK UP

During drilling operations, a pipe is considered stuck if it cannot be freed and pulled

out of the hole without damaging the pipe and without exceeding the drilling rig’s

maximum allowed hook load. Stuck up occurs due to one of the following reasons:

Differential sticking.

Mechanical sticking.

Key seating.

Well bore instability.

Mud loss.

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DIFFERENTIAL STICKING:

Differential-pressure pipe sticking

occurs when a portion of the drillstring

becomes embedded in a mudcake (an

impermeable film of fine solids) that forms on

the wall of a permeable formation during

drilling. As it is well known, no well is

perfectly vertical. At all times the drill string is

in contact with the well bore. The pressure

acting on the side in contact with the well bore

is equal to the formation pressure whereas on

the remaining side it is equal to the hydrostatic

head of mud. The differential pressure so

caused results in the string being pressed

against the well bore and subsequently getting

differentially stuck although circulation is

normal.

PREVENTION:

Maintain the lowest level of drilled solids in the mud system, or, if

economical, remove all drilled solids.

Select a mud system that will yield smooth mudcake (low coefficient of

friction).

Maintain drillstring rotation at all times, if possible.

REMEDIES:

Mud-hydrostatic-pressure reduction in the annulus

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Oil spotting around the stuck portion of the drillstring

Washing over the stuck pipe

Some of the methods used to reduce the hydrostatic pressure in the annulus include:

a. Reducing mud weight by dilution

b. Reducing mud weight by gasifying with nitrogen

c. Placing a packer in the hole above the stuck point

MECHANICAL STUCK UP:

The causes of mechanical pipe sticking are inadequate removal of drilled

cuttings from the annulus; borehole instabilities, such as hole caving sloughing, or

collapse; plastic shale or

salt sections squeezing

(creeping); and key

seating.

Excessive drilled-

cuttings accumulation in

the annular space caused

by improper cleaning of

the hole can cause

mechanical pipe sticking,

particularly in

directional-well drilling.

The settling of a large

amount of suspended

cuttings to the bottom

when the pump is shut

down, or the downward

sliding of a stationary-

formed cuttings bed on the low Settled Cuttings Beds

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side of a directional well can pack a bottomhole assembly (BHA), which causes pipe

sticking.

The drill string can become mechanically stuck because of the following:

Sloughing Sales: In thus hole shales absorb water from the drill fluid,

expanding, sloughing off, and falling downhole. Large masses may lodge

around drill collars and stabilizers, sticking the drill string and blocking

circulation. Abnormally pressured shale, steeply dipping shale beds, and

erosion by drilling fluid can also cause hole wall to cave in.

Under gauge Holes: Pipe stuck in under gauge hole often happens in shale

formations. If the formation swells but does not slough off, the deformed layer

may close around the drill pipe, cutting off circulation and preventing passage

of the tool joints, drill collars, or bit. A buildup of mud solids can have the

same effect, especially in a permeable zone where water is lost to the

formation.

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Inadequate hole cleaning that is failure of the circulating system to clean

cuttings or other material from the hole can result from sloughing shale, drill

string washout above the bit, a low circulation rate in a large hole having

unweighted mud, or lost returns. Inadequate hole cleaning permits a buildup

of solids around the bit and collars.

PREVENTIONS:

Maintain adequate flow rates specially in high angle wells.

Rule of thumb for vertical wells – annular velocity should be twice the

cuttings settling rate.

It is a good practice to wash last few stands to bottom.

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REMEDIES:

If cuttings accumulation or hole sloughing is the suspected cause, then

rotating and reciprocating the drillstring and increasing flow rate without

exceeding the maximum allowed equivalent circulating density (ECD) is

a possible remedy for freeing the pipe.

If hole narrowing as a result of plastic shale is the cause, then an increase

in mud weight may free the pipe.

If hole narrowing as a result of salt is the cause, then circulating fresh water

can free the pipe.

KEY SEATING:

Key seating occurs when drill pipe in tension wears an under gauge groove in

the wall of a curved section, or dogleg, of the hole. When the drill string is raised or

lowered, tool joints or drill collars may become lodged in the lower or upper end of

the key seat.

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CAUSES:

High side loads.

Long rotating hours.

High side loads exists when the dog leg is at a shallow depth.

Rotating off bottom creates more tension at the dogleg.

REMEDIES:

Jar in the opposite direction the pipe was moving before it got stuck.

Since all stuck up in key seats takes place during trip out – apply torque

and jar down.

Once free down ward back ream out.

WELLBORE INSTABILITY-:

Wellbore stability is the prevention of brittle failure or plastic deformation of

the rock surrounding the wellbore due to mechanical stress or chemical imbalance.

Prior to drilling the mechanical stresses in the formation are less than the strength of

the rock. The chemical action is also balanced, or occurring at a rate relative to

geologic time. Rocks under this balanced or near balanced state are stable.

After drilling, the rock surrounding the wellbore undergoes changes in tension,

compression, and shear loads as the rock forming the core of the hole is removed.

Chemical reaction also occur with exposure to the drilling fluid.

Under these conditions the rock surrounding the wellbore can become unstable,

begin to deform, fracture, and cave into the wellbore or dissolve into the drilling

fluid.

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Excessive rock stress can collapse the hole resulting in stuck pipe. Hole-squeezing

mobile formations produce tight hole problems and stuck pipe. Cavings from failing

formation makes hole cleaning more difficult and increases mud and cementing

costs.

PREVENTIONS

Though total prevention borehole instability is not possible , but the drilling engineer

can mitigate the problems of borehole instabilities by adhering to good field

practices. These practices include:

Proper mud-weight selection and maintenance

The use of proper hydraulics to control the ECD

Proper hole-trajectory selectio, and the use of borehole fluid compatible

with the formation being drilled

LOST CIRCULATION -:

Lost circulation is the loss of borehole mud to the exposed formations in the

well and may result in stuck pipe. Mud flowing into the formation implies that there

is less mud return at the flow line than is being pumped or that there is total loss of

circulation. The reduction in the annular velocity of the mud in the zone above the

loss zone reduces the carrying capacity of the mud. Cuttings may accumulate in the

low velocity region and may fall back into the bottom of the hole resulting in stuck

pipe due hole pack off. The drop in level of mud in annulus causes a reduction in

hydrostatic head and may lead to lesser wall support of an exposed shale section

causing sloughing. This will further deteriorate the well bore stability and may cause

the pipe to get stuck against the shale section also.

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There are generally three types of lost circulation-:

1) Seepage Loss (< 10 bbl/hr)

2) Partial Loss ( 10-50 bbl/hr )

3)Severe Loss (> 50 bbl/hr)

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CEMENT STICKING-:

Although cement sticking can result

from a mechanical malfunction such

as pump failure or leak in a string of

pipe, there are three primary causes:

displacement has been

miscalculated, the hole has washed

out as a result of efforts to contain a

downhole blowout, and efforts have

been made to prevent excessive lost

circulation. While cementing. The

potential danger lies in the unlikely

chance of flash set causing the string

to be cemented in the hole.

Identification

Unable to reverse circulate.

Unable to pull out the cementing string.

Immediate action

Pull to the maximum safe limit of the string.

Attempt to circulate at a higher pressure than that available with rig

pumps (use cementing unit).

Preventive action

Technical water should be tested for designing cement slurry.

Simulate down hole conditions prior to cement job and Make all

arrangements for reversing out in advance.

Cementing units and mud pumps should be checked prior to taking up

cementing job.

Recovery process

Back off and wash over the cemented string.

Cement sticking

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2) STRING FAILURE-:

The main causes of drill string failure are:

a. Fatigue failure.

b. Washout.

c. Twist off

d. Tensile failure.

e. Collapse.

f. Burst.

g. Down hole vibrations.

a) Fatigue failure –:

Mostly drill pipe failures are caused by fatigue. Fatigue is the combined effect of

tension, torsion and bending. The cyclic reversal of stress that results in as the string

is rotated. Fatigue is accelerated when string is rotated in a section of directional &

crooked hole. Failure of the drill pipe due to fatigue takes place in the pipe body

generally in the area where slip is set. Fatigue fractures are progressive beginning

as micro cracks that grow under the action of cyclic stress. The rate of propagation

is related to the applied cyclic load. Since the crack develops from the inside of the

drill pipe and no plastic deformation occurs these cracks are very difficult to detect.

b) Washout-:

A washout is a place where a small opening result in forcing the drilling fluid through

pipe. It is usually the result of a fatigue crack penetrating the wall of the pipe. Wash

out may also be caused by a damaged shoulder of box and/or a damaged pin.

Wearing out and tool joint gets worn out and connection not made up to its

recommended torque.

c) Twist off-:

Usually caused by the fatigue crack extending around the pipe and causing the pipe

to break. This type of failure usually occurs in the following manner

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Most failures occur when rotating or when picking the pipe off bottom immediately

after drilling rather than pulling on stuck pipe. Most failures occur within 1m of the

tool joint on either end of the pipe. Failure that originate from the outside of the pipe

are usually associated with slip marks or other surface damages such as gouges,

welding arc spots, marks made by drill pipe protectors, etc.

d) Tensile failure-:

The drill string can fail due to tension alone i.e. the total weight of the drill stem

member together exceeds the pipe yield value. The design of the drill stem for static

tensile load requires sufficient strength in the top most member of each size, weight,

grade and class of drill pipe to support the buoyed weight of all hanging load below

it. Rated tensile capacity is the product of the minimum yield strength and its cross

sectional area. The actual tensile strength will be more because the yield strength is

normally high than the minimum specified tensile strength.

e) Collapse failure-: Drill pipe may be subjected to an external pressure higher than

the internal pressure. This condition usually occurs during drill stem testing and may

result in collapse of the drill pipe. The collapse pressure is the maximum in the lower

most drill pipe. The drill pipe will be mashed flat or into a half moon shape.

f) Burst failure-: Also this type of failure is extremely rare but it can occur in any

operation with a high differential pressure from inside the pipe, for example when

well testing or fracturing.

g) Down hole vibrations-: Although some down hole vibrations are inevitable,

severe down hole vibration can cause drill string fatigue (washout / twist off),

crooked drill string, premature bit failure and reduced penetration rates

Pipe Failure Prevention-:

Fatigue failures can be mitigated by minimizing induced cyclic stresses and

insuring a noncorrosive environment during the drilling operations.

Cyclic stresses can be minimized by controlling dogleg severity and drillstring

vibrations.

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3) BIT FAILURE-:

Fishing of bits especially roller bit cones is one of the most common fishing

operations.

Recovery of bit cones in soft formation

This depends on the size & number of bit cones left in the well. The following

is a generalized procedure for recovery of lost bit cones. If only one cone is lost in

the well, a hard formation mill tooth bit run with a junk sub will break up the cone.

Part of the junk will be walled off and the remaining will be collected in the junk

sub. Usually the junk walled off will not fall back in the hole. Run a reverse

circulation junk basket if two or more rollers are left in the hole.

Recovery of bit cones in hard formation

Since there is a possibility of the bit getting under gauge prior to its failure it

is advisable to make a bit trip to prove the hole to bottom, especially prior to running

a junk basket. There have been cases of the junk basket getting mechanically stuck

against a cone which is partially embedded in the wall of the well bore. The most

effective way to remove bit cones is to mill them with a concave mill run along with

a junk sub. A clean out trip with a hard formation mill tooth bit and junk sub will

clear the bottom of the hole. Run this bit only for a short time to prevent leaving

teeth, and possibly more cones.

4) CASING FAILURE-:

Failure of casing is an area of increasing concern. The extent of casing failure covers

wells offshore and onshore varying in size from 13 3/8” to 5 ½”. Failure of casing

occurs mainly due to:

1) Leakage from joints due to improper make up.

2) Wear out of intermediate casing due to tool joint of drill string /junk inside casing.

3) Collapse & burst casing.

4) Improper design.

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FISHING-:

Fishing–It is the process of removing a fish or junk from the borehole.

A fish is a part of the drill string (tubing, sucker rods, wire, rope or cable) that

separates from the upper remaining portion of the drill string while the drill string is

in the well. This can result from the drill string failing mechanically, or from the

lower portion of the drill string becoming stuck or otherwise becoming disconnected

from drill string upper portion. Such an event will instigate an operation to free and

retrieve the lower portion (or fish) from the well with a strengthen specialized string

Junk –is usually described as small items of non-drillable metals that fall or are left

behind in the borehole during the drilling, completion, or workover operations.

These non-drillable items must be retrieved before operations can be continued. It is

important to remove the fish or junk from the well as quickly as possible. The longer

these items remain in a borehole, the more difficult these parts will be to retrieve.

Further, if the fish or junk is in an open hole section of a well the more problems

there will be with borehole stability.

There is an important tradeoff that must be considered during any fishing operation.

Although the actual cost of a fishing operation is normally small compared to the

cost of the drilling rig and other investments in support of the overall drilling

operation, if a fish or junk cannot be removed from the borehole in a timely fashion,

it may be necessary to sidetrack (directionally drill around the obstruction) or drill

another borehole. Introduction

Fishing A

ssem

bly

30 | P a g e

Thus, the economics of the fishing operation and the other incurred costs at the well

site must be carefully and continuously assessed while the fishing operation is

underway. It is very important to know when to terminate the fishing operation and

get on with the primary objective of drilling a well.

The most causes of fishing jobs, not necessarily in order of frequency, are:

1.Twist Off: a parting of the drill string caused by metal fatigue or washout

2. sticking of the drill string

3. bit and tool failures and

4. foreign objects such as hand tools, logging instruments, and broken wireline

or cable lost in the hole.

Several kind of tools are lowered into the wellbore to catch the fish this depends on

factors like type of fish and its size. Generally, used fishing tools are:

Impression Block: Inspecting the break on the

part of the pipe that is pulled from the hole may

provide a good reverse image of the top of a twist

off.

One method that is sometimes used to assess the

condition of the top of a fish is to run an impression

block.

A typical impression block consists of a

block of lead, having a circulation port,

molded onto a steel body.

o The block is made up on drill pipe and

collars and run into the hole until it is

just above the fish.

o Circulation is started to wash all

settlings off the top of the fish so that

a good impression can be obtained.

o The block is lowered gently to touch

the fish, and weight is then applied.

Impression Block

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o The top of the fish indents the bottom of the soft

lead block, leaving an impression that can be examined and

measured at the surface.

Mills: If a part of drill string has broken off in open hole and it is not stuck,

the fishing job consists mainly of locating and engaging the top of the fish

with an appropriate tool. If the top of the broken-off pipe is badly split or

twisted, it requires that the damaged metal is removed to give a fish a more

acceptable shape, because most fishing techniques require a section of straight

undamaged pipe to make a firm catch.

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Overshot: A typical circulating and

releasing overshot consists of thr#ee outside

parts:

a top sub,

a bowl, and

a guide.

The top sub connects the overshot to the

fishing string while the bowl may be fitted

with different types of equipment to grasp

the fish and different guides to help center

the fish beneath the tool. The fishing string

is run to within a few feet of the top of the

fish. Circulation starts to clean cuttings and

settlings off the top of the fish and to clean

out mud cake from inside the overshot. The

fishing string is slowly lowered to touch the

top of the fish and establishes its exact

depth. When the fish has been tagged, hook

load decreases; the position is marked on the

kelly.

The string is raised, and, with slow rotation to the right, lowered slowly

without circulation, if the overshot is centered over the fish, the lowering and

right-hand rotation of the string forces the grapple upward within the tapered

helix of the bowl, allowing the grapple to expand and the fish to enter the

overshot. After the string has been lowered, the weight indicator should

register a decrease. When the fish is engaged, rotation is stopped and all torque

of the string relieved. Than upward strain is taken. This causes the fish to pull

the grapple downward and the wickers on the grapple to bite into the fish. If

the fish is gripped tightly, the weight indicator will show an increase.

Circulation is started, without rotation, to clean out the hole before the fish is

brought to the surface. If it is not possible to pull out the string it must be

stacked. To break out a string from the fish, the overshot is bumped down and

rotated to the right and gradually raised until it is clear of the fish.

Overshot

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WELL CONTROL

Introduction

During drilling it is necessary to keep the well under primary control at all times.

By primary control we mean that the hydrostatic head exerted by the column of mud

should be greater than the formation pore pressure (formation pressure). If for some

reason the primary control over the well is lost then influx of formation fluids may

take place and if this influx is not controlled then the formation fluids will flow to

the surface in an uncontrolled manner which will eventually lead to a blowout. The

consequences of a blowout are:

1. Loss of human life

2. Loss of reservoir fluids

3. Loss of rig

4. Irreparable damage to the environment

Therefore, it is necessary to learn about the methods which are used to prevent a

blowout. To prevent uncontrolled flow of formation fluids to the surface secondary

control over the well is initiated. This includes closing the Blowout Preventers

(BOP’s) generally the Hydril (Annular Preventer).

Well control deals with the methods used to keep the well under control.

The influx of formation fluids to the well bore is known as a kick. Now the severity

of a kick depends on various factors like:

1. Type of formation: Severity of kick will be more if the formation has high

permeability and porosity. Therefore, kicks from sandstone are more severe

than that from shale.

2. Pressure: During the time of kick the formation pressure is more than the

hydrostatic pressure. Now severity of a kick is directly proportional to this

pressure difference.

3. Type of Influx: Kick will be more severe if the influx is of gas as compared

to oil or water as it expands much faster than the other two.

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Reasons for loss of Primary Control

Primary Control over the well is lost for two reasons:

The bit has penetrated a high pressure zone which was not predicted by the

geologists as a result of which the mud in use has failed to provide the

required hydrostatic head.

For some reason the hydrostatic head exerted by the mud has reduced. Now

as the hydrostatic head depends on mud density and height of mud column

it is assumed that anyone of the two has decreased.

Reasons for reduction in mud weight

Mud weight reduces due to three reasons:

Excessive Dilution: When the amount of total solids in the mud increases

its rheological properties like viscosity changes. The mud is diluted with

water to achieve the required viscosity. Mud weight may decrease if too

much water is added to it.

Solids Removal: Drill cuttings are removed from the mud as it reaches the

surface by means of solids removal equipment. If these equipments are not

properly designed then they may also remove the weighting materials (eg.

Barite) added to the mud which will reduce its weight.

Gas Cut: If gas from the formation seeps into the drilling mud then it will

reduce its density and hence its weight. Gas expands as it rises up the

annulus the reduction in mud weight at the bottom is very less to that at the

surface.

Reasons for reduction in height of mud column

Height of the mud column may decrease due to:

Tripping: The height of the mud column falls as the drill string is

pulled out of hole. The hydrostatic pressure exerted by the mud

column also decreases. If the hydrostatic head becomes less than the

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formation pressure then the chances of a kick increases. To avoid

this mud equal to the volume occupied by the drill string should be

pumped into the well by using a trip tank.

Swabbing: When the drill string is pulled out of hole low pressure

zone is created below the bit as a result of which formation fluids

are sucked into the wellbore. Factors affecting amount of swabbing

are:

Adhesion of drill mud to the drill string.

Speed of pulling up the pipe.

Annular Clearance.

Thickness of mud cake.

Inefficient hole cleaning.

Lost Circulation: This occurs while drilling a highly permeable of

fractured formation. Whole mud is lost to these fractures or

formations. Sometimes the formations get fractured if the pressure

gradient of the mud is greater than the formation’s fracture gradient.

Loss circulation can be classified as:

Seepage loss: 0-10 bbl/hr

Partial loss: 10-50 bbl/hr

Severe Loss: More than 50 bbl/hr

Warning Signs Of A Kick

As influx enters the wellbore from the bottom the drilling crew relies only on

the indications at the surface so as to get an idea of what is happening downhole.

Out of a number of indications that a driller may get while influx enters the wellbore

downhole only some directly indicate that kick has entered are therefore, such

indications are called Primary Indicators. Others are not so direct and can be due to

other factors also so such indicators are called Secondary Indicators.

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Primary Indicators Of A Kick are:

Increase in flow rate: While the mud pumps are circulating at a

constant rate, the rate of flow out of thewell, Qout should be

equal to the rate of flow into the well, Qin. If Qout increases

(without changing the pump speed) this is a sign that formation

fluids are flowing into the wellbore and pushing the contents of

the annulus to the surface. The flowrate into and out of the well

is therefore monitored continuously using a differential

flowmeter. The meter measures the difference in the rate at

which fluid is being pumped into the well and the rate at which

it returns from the annulus along the flowline.

Pit Gain: If the rate of flow of fluid into and out of the well is

constant then the volume of fluid in the mud pits should remain

approximately (allowing for hole deepening etc.) constant. A rise

in the level of mud in the active mudpits is therefore a sign that

some other fluid has entered the system (e.g. an influx of

formation fluids). The level of the mud in the mudpits is therefore

monitored continuously. The increase in volume in the mud pits

is equal to the volume of the influx and should be noted for use

in later calculations.

Returns from a well when pumps are switched off: When the

rig pumps are not operating there should be no returns from the

well. If the pumps are shut down and the well continues to flow,

then the fluid is being pushed out of the annulus by some other

force. It is assumed in this case that the formation pressure is

higher than the hydrostatic pressure due to the column of mud

and therefore that an influx of fluid is taking place.

Improper whole fill-ups on trips: The wellbore should to be

filled up with mud when pipe is pulled from the well. If the

wellbore overflows when the volume of fluid, calculated on the

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basis of the volume of drillpipe removed from the well, is

pumped into the well then fluids from the formation may have

entered the well.

Secondary Indicators Of A Kick are:

Drilling Break: A drilling break is an abrupt increase in the rate

of penetration and should be treated with caution. The drilling

break may indicate that a higher pressure formation has been

entered and therefore the chip hold down effect has been reduced

and/or that a higher porosity formation (e.g. due to under-

compaction and therefore indicative of high pressures) has been

entered. However an increase in drilling rate may also be simply

due to a change from one formation type to another.

Changes in hook load

Increase in flowline temperature

Increase in chloride content of mud

Changes in pump pressure: If an influx enters the wellbore the

(generally) lower viscosity and lower density formation fluids

will require much lower pump pressures to circulate them up the

annulus. This will cause a gradual drop in the pressure required

to circulate the drilling fluid around the system. In addition, as

the fluid in the annulus becomes lighter the mud in the drillpipe

will tend to fall and the pump speed (strokes per min.) will

increase. Notice, however, that these effects can be caused by

other drilling problems (e.g. washout in drillstring, or twist-off).

Gas cut mud: When gas enters the mud from the formations

being drilled, the mud is said to be gascut. It is almost impossible

to prevent any gas entering the mud column but when it does

occur it should be considered as an early warning sign of a

possible influx. The mud should be continuously monitored and

any significant rise above low background levels of gas should

be reported. Gas cutting may occur due to:

38 | P a g e

Increase in number of drill cuttings

Whenever any of the above mentioned indications are observed a Flow Check is

made. The process of making a flow check is:

PROCEDURE FOR FLOW CHECK

Pick up the Kelly till the tool joint appears

Shut the mud pumps

Keep the drill string moving up or down

Check the pit gain

If there is no pit gain resume drilling by increasing the mud

weight by the amount so as to compensate for the Annular

Pressure Losses. But if there is pit gain close the Annular

Preventer of the BOP.

The process of pumping heavy mud to stop influx of fluids and to regain primary

control over the well is called killing a well. These process are case dependent and

are described below:

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Methods of killing a well when Drilling Bit is at the bottom

1. Wait and Weight Method (One Circulation Method)

2. Driller’s Method (Two Circulation Method)

1. Wait and Weight Method

The procedure used in this method is to circulate out the influx and circulate in

the heavier mud simultaneously. The influx is circulated out by pumping kill mud

down the drill string displacing the influx up the annulus. The kill mud is pumped

down the drill string at a specific rate while the pressure in the annulus is

controlled through the choke so that the bottomhole pressure does not fall,

allowing further influx to occur.

Let us consider the following figure the initial pressure in the drill string is

equal to SIDPP + Losses while circulating at SCR (Pc1) as the kill mud is travels

down to the drill string pressure becomes equal to Pc2. After that it is constant.

Note: Pc1 should be calculated during regular drills conducted to decrease crew’s

response time during emergency.

Where, Pc2 = Pc1*(ρkmw/ρomw)

ρkmw = Kill Mud gradient

ρomw = Original Mud gradient

40 | P a g e

The casing pressure increases and reaches to its maximum value when it is at the

surface (this case is specifically for gas, in case of oil or water the expansion in

volume is not so great). As the influx is circulated out of the annulus the annular

pressure drops to zero.

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2. Driller’s Method (Two Circulation Method)

In this method influx is circulated out with the mud which is already there in the

well and after the influx has been circulated out of the well kill mud is pumped

into the well. While circulating out the influx the choke is opened in such a way

that there is enough back pressure at the bottom so that no further influx takes

place.

While circulating out the influx the drill pipe pressure is held constant and while

pumping the kill mud the casing pressure is held constant.

Here in the first circulation as the kill mud is not pumped into the drill string its

pressure will remain constant (SIDPP + Pc1). The casing pressure will continue

to rise the following depicts the situation where gas influx has taken place. It will

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reach to its peak value when the influx reaches near the surface. As thinflux is

circulated out through the choke the casing pressure will drop to SIDPP.

In second circulation the drill string pressure will drop as the kill mud is pumped

through it. It will drop in a linear manner till the time the kill mud reaches the bit

43 | P a g e

and then will become equal to Pc2. Now, as the kill mud travels up the annulus

the casing pressure will decrease linearly from SIDPP to zero.

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3. Volumetric Method of killing a well

This method of killing a well is used when the well cannot be circulated. Generally,

the bit is not at the bottom and there is little or no drill pipe in the hole. The method

can be divided into 2 stages namely:

Bleeding

Lubrication

Bleeding

In this process the influx (gas) is brought to the surface by bleeding of the

choke while keeping the bottom hole pressure constant. Now the bottom hole

pressure is sum of annular pressure and hydrostatic pressure exerted the mud.

As the influx rises the hydrostatic pressure decreases while the annular

pressure increases. Calculations are made so that the amount of mud required

to be bled off the annulus to maintain a constant bottom hole pressure can be

known.

Lubrication

This process starts when the gas it at the surface. The kill mud is pumped

into the annulus to increase the annular hydrostatic pressure constant BHP is

maintained by bleeding gas through the choke to decrease annular surface

pressure by the same amount. This process continues till gas has been

completely circulated out of the well.

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Blowout Prevention Equipment (BOP)

It is the equipment used to shut the well in case an influx takes place. Closing

the BOP marks the start of initiating Secondary Control over the well. The Surface

Casing acts as the structural support for this equipment. The BOP has several valves

which can be closed to close the annulus or well as per the demand. Drilling of

problematic zones is done only after installation of well head and BOP. This ensures

that the well can be shut-in in time during emergency.

BOP HOOK UP FOR 8 1/2” PHASE DRILLING (3CP X5M)

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NOTE:

1. The well head on which the BOP is installed should have the same pressure rating

as the BOP.

2. To ensure proper functioning of the BOP should be tested at regular interval.

Now, another important aspect is selecting a BOP. BOP is categorised on the basis

of its pressure rating as:

a. Low Pressure BOP (2M or 2000 psi)

BOP HOOK UP FOR 12 1/4” PHASE DRILLING (4CP X 10M)

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b. Normal Pressure BOP (3M or 3000 psi and 5M or 5000 psi)

c. Abnormally High Pressure BOP (10M or 1000 psi and 15M or 15000 psi)

The BOP will be selected on basis of the maximum formation pressure that will be

encountered during drilling a particular well.

BOP’s are also classified as:

Annular Preventer

Ram Preventer

Annular Preventer: It is located at the top of the BOP. It closes the annulus

and is the first valve which is closed after influx of formation fluids takes

place. The sealing element is made up of high quality rubber which is mounted

on metal ribs. It can be compressed against the drill pipe by pistons operating

on hydraulic power. The beauty of this preventer is that it can close around

any size of drill pipe or even openhole.

Annular Preventer

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Functioning Of An Annular Preventer

1. In order to close the annular preventer hydraulic pressure is applied on the

closing chamber.

2. This raises the piston which in turn squeezes the packing unit inward

thereby, closing the annulus.

Ram Type Preventer

Ram type preventers derive their name from twin ram elements which make

up its closing mechanisms.

Closing the RAM Preventer

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1. Blind Rams – It completely closes off the annulus when there is no drill pipe

in the hole.

2. Pipe Rams – It seals off around drill pipes having a fixed diameter. Now

variable Pipe Rams are used and these can seal around a range of drill pipe

sizes.

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3. Shear Rams- These are special type of blind rams which can cut through the

drill pipe in case of emergency and should be used as a last resort.