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0 | P a g e
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
1 | P a g e
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)
2 | P a g e
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 .
3 | P a g e
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
4 | P a g e
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
5 | P a g e
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.
6 | P a g e
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.
7 | P a g e
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
8 | P a g e
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
9 | P a g e
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
10 | P a g e
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.
11 | P a g e
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.
12 | P a g e
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.
13 | P a g e
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.
14 | P a g e
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.
15 | P a g e
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.
16 | P a g e
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.
17 | P a g e
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
18 | P a g e
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
19 | P a g e
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.
20 | P a g e
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.
21 | P a g e
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.
22 | P a g e
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.
23 | P a g e
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.
24 | P a g e
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)
25 | P a g e
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
26 | P a g e
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
27 | P a g e
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
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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:
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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
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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
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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.