FISHING ECONOMICS

 FISHING ECONOMICS
The option of abandoning fishing operations and sidetracking the well should be taken on
economic grounds unless there are exceptional logistical, legislative or safety grounds.
Before giving up on a fishing job the cost of sidetracking operations together with re-drilling
to the original depth needs to be calculated. This cost when converted to equivalent rig day
rate days can be used to assess the amount of time that it is economic to pursue fishing
operations. The procedure is as follows:
a. Calculate the total cost of the fish to be left in hole.
b. Calculate the cost of backing-off and setting of a cement plug prior to sidetracking. This
should include all rental and consumable items, including personnel.
c. Calculate the cost of the sidetrack including directional equipment and casing milling
equipment (if applicable).
d. Calculate the cost of drilling to the original depth. This should be based on the time to drill
the original section plus an additional 10% to account for the directional aspects.
Total cost is therefore = a + b + c + d.
This should be converted to rig days by dividing the total cost by the rig day rate.
Abandonment of fishing operations should be considered when the fishing time has reached
½ the above number of days, and the probability of completing the fishing operation is
gradually becoming small.

Hole Problems Lec ( 3 )

MECHANICAL STICKING 

CAUSES OF MECHANICAL STICKING
In mechanical sticking the pipe is usually completely stuck with little or no circulation. In
differential sticking, the pipe is completely stuck but there is full circulation.Mechanical
sticking can occur as result of the hole packing off (or bridging) or due to formation & BHA
(wellbore geometry).
Hole pack off (bridging) can be caused by any one or a combination of the following
processes:
1. Settled cuttings due to inadequate hole cleaning
2. Shale instability
3. Unconsolidated formations
4. Fractured and faulted formations
5. Cement blocks
6. Junk falling in the well
The formation & BHA (wellbore geometry) can also cause mechanical sticking as follows:
1. Key seating
2. Mobile formations
3. Undergauge hole
4. Ledges and micro doglegs
Understanding the cause of the mechanical sticking problem is key to solving the problem.
This is because the cause determines the action required to free the pipe. For example, if the
pipe becomes stuck while running in an open hole, it is likely that the BHA has hit a ledge or
gone into an undergauge hole. In other words, the sticking problem is due to the geometry of
the wellbore. As will be seen later, the freeing action depends largely on identifying and
curing the problem that caused mechanical sticking.
A discussion of each of the above processes will now follow.

HOLE PACK OFF CAUSES
1- SETTLED CUTTINGS
Settled cuttings due to inadequate hole cleaning (Figure 12.4) is one of the major causes of
stuck pipe. Best hole cleaning occurs around large OD pipe such as drillcollars, while
cuttings beds can form higher up the hole where the pipe OD is smaller. The problem of
settled cuttings is particularly severe in horizontal and high directional wells. In these wells,
when the pipe is moved upwards, the cuttings may be compacted around the BHA. This can
result in complete packing off of the drillstring and eventual pipe sticking.
With increasing deviation of the wellbore, drilling fluid parameters, drilling practices and
hydraulics should be optimised in order to effectively clean the hole.
In vertical wells, good hole cleaning is
achieved by the selection and
maintenance of suitable mud parameters
and ensuring that the circulation rate
selected results in an annular velocity
(around 100-120 ft/min) which is greater
than the slip velocity of the cuttings.
Highly inclined wells are particularly
difficult to clean due to the tendency of
drilled cuttings to fall to the low side of
the hole.In a highly deviated well, the
cuttings have only a small distance to fall
before they settle on the low side of the
hole and form a cuttings bed. Cuttings
beds develop in boreholes with
inclinations of 30 degrees or greater, depending on the flow rates and suspension properties
of the drilling fluid.Complete removal of cuttings beds by circulation may be impossible.
Once cuttings beds have formed, there is always a risk that on pulling the pipe up the hole,
the cuttings are dragged from the low side of the hole forming a cuttings pile (Figure 12.4).
If this pile accumulates around the BHA, it may plug the hole and cause the pipe to
mechanically stuck.
Besides causing stuck pipe, settled cuttings can result in:
• formation break down due to increased ECD
• slow ROP
• excessive overpull on trips
• increased torque
Hole cleaning is controlled by a number of parameters which were discussed in Chapter 8.
These include:
1. mud rheology, in particular the YP and gel strength
2. flow rate
3. hole angle
4. mud weight
5. ROP
6. hole diameter
7. drillpipe rotation
8. presence of wash outs

2 - SHALE INSTABILITY
Shale represents 70% of the rocks encountered whilst drilling oil and gas wells. Also shale
instability is by far the most common type of wellbore instability. Shales are classified as
being either brittle or swelling.
Brittle Shales
Instability in brittle shales is caused
mainly by tangential stresses around the
wellbore which are induced as a result of
the well being drilled. The induced
stresses depend on the magnitude of the
in-situ stresses, wellbore pressure, rock
strength and hole angle and direction.
Formation dip may also be a
contributory factor to brittle shale
failure. A safe mud envelope may be
established which can be used to
determine the safe mud weights to
prevent either tensile failure or collpase (compressive) failure.
Brittle shales tend to fail by breaking into pieces and sloughing into the hole. Rig indications
of brittle shale failure include:
• large amounts of angular, splintery cavings when circulating the well
• drag on trips




• large amounts of hole fill.

3 - Swelling Shales
Shales swelling (Figure 12.6) can be caused by hydrational processes or by the osmotic
potential which develops between the pore fluid of the shale and drilling fluid salinity.
The swelling of shales (Figure 12.6) is controlled by several complex factors including:
• Clay content
• Type of clay minerals (ie hydratable or inert)
• Pore water content and composition
• Porosity
• In-situ stresses
• Temperature
The degree of clay hydration depends on
the clay type and the cation exchange
capacity (CEC) of the clay content. The
greater the CEC, the more hydratable is the
clay. In drilling operations the following
clay types are encountered:
• Smectite with CEC of 80-150
meq/100g. Most of the
hydratable shales (termed
gumbos) belong to this group.
Bentonite clays belong to the
smectite group.
• Illite with CEC of 10-40 meq/100g.
• Chlorite with CEC of 10-40 meq/100g.
• Kaolinite with CEC of 3-10 meq/100g.
To aid the understanding of shale swelling, the following points must be considered:
1. The permeability of shales is very low, typically in the range of 10 -9 to 10 -6 Darcy.
(1 md = 10 –13 m2)
2. Thus, filter cakes do not form on shale surfaces.
3. However, water can still migrate into the shale (helped by the mud overbalance).
4. Water infusion into the shale will allow chemical effects to start working inside the
shale and at the exposed surfaces of the wellbore.
5. The pore pressure inside the shale section will also increase, contributing to destabilisation.
6. The low permeability of shale means that swelling effects can take considerable
time and shale instability can be a delayed effect.
Water can flow into or out of the shale through several processes; the most important ones
are hydrational and osmotic forces:
1. Hydration: This is by far the most common cause of shale hydration where water
flows into the shale and hydrate the clay plates. Highly hydratable shales are
composed of predominantly smectite- based clays. These clays (e.g.
montmorillonite) absorb water into the inner-layer space due to the high negative
charge on the surface of the clay platelet. This process results in the expansion of
the clay to several times its original volume.
Hydratable shales are usually found near the surface ±7000
At grater depths, the process of diagenesis converts the clay minerals into more stable forms, However, hydratable shales have been found in some wells at depths
greater than 7000 ft due to the inhibition of the diagenetic processes.
2. Chemical osmosis: This type of flow occurs at semi-permeable membranes which
are permeable to water and impermeable to solute ions or molecules. Shale surface
acts as a semi-permeable membrane allowing water to flow into or out of the shale
depending on the solute concentration of the mud and pore water of the shale. Water
flows through the semi-impermeable membrane from the low concentration to high
concentration solution. In terms of chemical jargon, water flows from solutions of
high water activity to solutions of low water activity until the concentrations of the
two solutions are equalised. (Water activity (aw): ratio of vapour pressure of water
in a solution, drilling mud or shale pore water to the vapour pressure of pure water
at the same temperature.)
3. Chemical diffusion: This is caused by the flow of solutes (soluble solids) from
areas of high concentration to low concentration. Hence if the concentration of
certain ions or molecules in the drilling mud is greater than those in the formation
water of the shale then the solute will flow into the formation provided there are no
barriers to flow. Solutes can also flow out of the shale if their concentration is
greater than that in the drilling mud. No flow will occur if solute concentration is the
same in mud and shale.
4. Hydraulic diffusion; water flows in the direction of decreasing hydraulic pressure
gradient (Darcy’s Law). This flow can only occur if the rock has permeability.
Shale hydration – Rig Site Indications 
• Soft, hydrated or mushy cuttings
• Clay balls in the flowline
• torque and drag fluctuations
• Shale shaker screens blind off
• Increase in LGS, filter cake thickness, PV, YP and MBT (Methlyene blue test)
• Increase or fluctuations in pump pressure
• Circulation is restricted or sometimes impossible
• Bit and stabiliser balling when POH
• Generally occurs while POH (Tight hole) and problems while logging
• Problems increase with time.

Shale hydration – Prevention and Cure
• Use Inhibited mud system or displace to OBM system if possible
• Maintain mud properties as planned
• Addition of various salts (potassium, sodium, calcium) will reduce chemical
attraction between shale & water
• Addition of encapsulating polymers to WBM
• Reduce exposure time and case off the hydrated shale as soon as possible
• Regular wiper trips
• Good hole cleaning (especially in extended reach wells, ERW)


3 - UNCONSOLIDATED FORMATIONS
Unconsolidated formations are usually encountered
near the surface and include: loose sands, gravel and
silts. Unconsolidated formations have low cohesive
strengths and will therefore collapse easily (Figure
12.7) and flow into the wellbore in lumps and pack off
the drillstring.
Surface rig indications of an impending stuck pipe
situation near top hole are: increasing torque, drag and
pump pressure while drilling. Other signs include
increased ROP and large fill on bottom.
A common remedial action is to use a mud system with
an impermeable filter cake to reduce fluid invasion into
the rock. Reduction of flow rate, and in turn annular velocity, will reduce erosion of the hole
and removal of the filter cake.



4 - FRACTURED AND FAULTED FORMATIONS
This is a common problem in limestone and chalk formations. Several symptoms can be
observed on surface including:
• large and irregular rock fragments on shakers
• increased torque, drag and ROP
• small lost circulation
These fractured and faulted formations may fall into the Wellbore as soon as they are drilled
as the stresses which originally held them together are relieved by the drilling of the hole. In
addition, excessive drillstring vibrations cause the pipe to whip downhole and break and
dislodge the exposed fractured/faulted rocks. Therefore it is important to reduce drillstring
whipping to prevent dislodging of rock fragments when drilling fractured and faulted rocks.
In all cases, it is imperative to keep the hole clean in order to reduce the chances of hole
packing off.
If the drillstring is stuck in limestone or chalk formations and cannot be freed by jarring, an
inhibited hydrochloric acid pill may be spotted around the stuck zone.The acid will react
with the chalk/limestones, dissolving the rock around the pipe.If the pill is successful the
pipe will be freed quickly.

5 - CEMENT BLOCKS
Stuck pipe can be caused by cement blocks falling from the rat hole beneath the casing shoe
or from cement plugs.
This problem may be prevented by minimising the rat hole to a maximum of 5 ft and also by
ensuring a good tail cement is placed around the shoe .
The drillstring can also be stuck in green cement which has not set properly. This usually
occurs after setting a cement plug inside the casing or open hole. If the drillstring is run too
fast into the top of the cement and if the cement is still green then the cement can flash set
around the pipe and cause the pipe to be permanently stuck.

The author has come across several situations where the top of the cement is soft when
tagged, but literally within seconds of tagging the cement, the cement flash sets around the
BHA causing mechanical sticking. One possible explanation for this sudden flash setting is
that the energy release while circulating and rotating is enough to cause flash setting. It is
recommended that circulation is started two to three stands above the expected top of cement
and that WOB should be kept to absolute minimum.
6 - JUNK
Several recorded incidents of pipe sticking occurred as a result of junk falling into the hole.
This include junk falling into the wellbore from the surface or from upper parts of the hole.
Typical junks dropped from surface include pipe wrenches, spanners, broken metal, hard
hats etc. This problem can be minimised by keeping the hole covered when no tools are run
in the hole.
Junks can also fall from within the well including broken packer elements, liner hanger slips
and metal swarf from milling operation.

HOLE PROBLEMS lec ( 2 )

DIFFERENTIAL STICKING FORCE

The differential sticking force is given by:
Differential sticking force (DSF) = (Hs - Pf) x effective contact area x friction factor (12.1)
whereHs = hydrostatic pressure of mud
Pf = formation pressure
In Equation (12.1), the most difficult terms to determine are the effective contact area and
the friction factor between the mud cake and the pipe steel. To a first approximation the
effective area may be calculated as the product of the height of the exposed permeable
formation times 20% of the perimeter of the drillpipe or drillcollars.
Another equation for estimating the contact area is given by
It should observed that none of the equations given for estimating the contact area are
completely valid as the contact area is affected by a number of variables including the
friction factor (time-dependent), the amount of bend in the drillpipe or collars, hole angle
and thickness of the filter cake.
The surface estimate of the thickness of the filter cake can be very different from that
occurring downhole.

Example : Differential Sticking Force
Determine the magnitude of the differential sticking force across a permeable zone of 30 ft
in thickness using the following data:
Differential pressure = 500 psi
Area of contact is 20% of effective drillpipe perimeter
Filter cake = 1/2 in (12.7mm); friction factor = 0.1.
Drillpipe OD: 5"
Solution
Perimeter of drillpipe = π x OD = π x 5 = 15.71 in
DSF = (Hs - Pf) x h x 20% x 15.71
= 500psi x (30ft x 12 in) x 20% x 15.71
= 565,560 lb

FREEING DIFFERENTIALLY STUCK PIPE .

There are basically two ways in which a differentially stuck pipe can be released:
• reduction of hydrostatic pressure
• spotting pipe release agents

 REDUCTION OF HYDROSTATIC PRESSURE 
The reduction of hydrostatic pressure is the obvious and most successful method of freeing a differentially stuck pipe. The lowering of the hydrostatic pressure reduces the side loading
forces on the pipe and therefore reduces the force required to free the pipe from the filter
cake. There are several methods by which this may be achieved. However prior to
implementing this action the following factors should be seriously considered:
1. Are there other pressured zones in the open hole section?
2. Will these exposed zones kick if the hydrostatic pressure is reduced?
3. The confidence level in the accuracy of pore pressure estimates made while drilling
and the pressure control equipment.
4. The effects of a reduction in hydrostatic pressure on the mechanical stability of all
exposed formations.
5. The volumes of base oil or water required to achieve the required reduction in
hydrostatic pressure. (This may well influence the method chosen).
All the above factors need to be carefully considered prior to reducing the hydrostatic
pressure as the potential for inducing a well control problem or formation instability are
considerably increased. The following methods for reducing hydrostatic pressure can be
used:
• circulation & reducing mud weight
• displacing the choke
• the ‘U’ tube method

CIRCULATION & REDUCING MUD WEIGHT
In this method, the drilling mud is circulated and its weight is gradually reduced. The
minimum mud weight required to balance the highest pore pressure in open hole should be
determined and the mud weight cut back in small stages. Close attention must be made to all
kick indicators whilst circulating down (reducing) the mud weight, frequent flow checks
should also be made. Whilst reducing the mud weight, tension should be held on the pipe.
Disadvantages of this methods are:
• It is slow, and remember the force required to free pipe is time dependent.
• The volume increase required may overload the surface pit handling capability.
This may be a serious problem when OBM is used.
• The active volume will be increasing during the reduction in mud weight,
making kick detection difficult.

DISPLACING THE CHOKE
This method is applicable to floating rigs where BOPS are placed on the seabed. The
hydrostatic pressure can be quickly and effectively reduced by displacing the choke line to
base oil or water. The well is shut in using the annular preventer and the displaced choke line
opened thereby reducing the overbalance.Note that the annular preventer isolates the
wellbore from the hydrostatic head of mud in the riser from rig floor to the annular preventer.
The advantage of this method is that if any influx is taken, the well can be immediately
killed by closing the choke and opening the annular. This action again exposes the well to the
active hydrostatic pressure from rig floor to TD. The disadvantage of this method is that the
amount of reduction in hydrostatic pressure is limited to the water depth. This may well
result in a limited reduction in shallow water, or in the case of deep water, an excessive
reduction in hydrostatic pressure

THE ‘U’ TUBE METHOD
The U-tube method is used to reduce the hydrostatic pressure of mud to a level equal or
slightly higher than the formation pressure of the zone across which the pipe got
differentially stuck.Clearly, the objective is to free the differentially stuck pipe safely without
losing control of the well by inadvertently inducing underbalanced conditions. A pipe free
agent should be spotted across the permeable zone prior to adopting the ‘U’ tube method.
The mathematics required for the full method is laborious, however,

SPOTTING PIPE RELEASE AGENTS
The severity of differentially stuck pipe can be reduced by the spotting of pipe release
agents. Pipe release agents are basically a blend of surfactants and emulsifiers mixed with
base oil or diesel oil and water to form a stable emulsion. They function by penetrating the
filter cake, therefore making it easier to remove and at the same time, reduce the surface
tension between the pipe and the filter cake.
Due to the time dependency of the severity of differential sticking, the pipe release agent
should be spotted as soon as possible after differential sticking is diagnosed. Typically the
pill will be prepared whilst initially attempting to mechanically free the pipe; ie by pulling
and rotating.
Example : Reduction of Hydrostatic Pressure
Calculate the volume of oil required to reduce the hydrostatic pressure in a well by 500 psi,
using the following data:
mud weight = 10 ppg
hole depth = 9,843 ft
drillpipe = OD/ID = 5 in/4.276 in
hole size = 12.25 in
specific gravity oil = 0.8 (6.7 ppg)
Solution
Initial hydrostatic pressure = 0.052 x10x 9843 = 5,118 psi
Required hydrostatic pressure = 5,118 - 500 = 4,618 psi
Thus,
New hydrostatic pressure = pressure due to (mud and oil) in drillpipe
4618 = 0.052x 10xY (mud) +0.052x (6.7) x (9843-Y) (oil)
where Y = height of mud in drillpipe.
Therefore,Y = 6,927 ft
Hence,
height of oil = 9,843 - 6,927 = 2,916 ft
volume of oil = capacity of drillpipe x height
= 290.79 ft3
= 51.7 bbl
Note that when the required volume of diesel oil is pumped inside the drillpipe, the
hydrostatic pressure at the drillpipe shoe becomes 4,618 psi, while the hydrostatic pressure
in the annulus is still 5,118 psi. This difference in the pressure of the two limbs of the well
causes a back-pressure on the drillpipe which is the driving force for removing the diesel oil
from the drillpipe and reducing the level of mud in the annulus. It is only when the annulus
level decreases that the hydrostatic pressure against the formation is reduced and the stuck
pipe may be freed.
When the formation pressure is unknown, it is customary to reduce the hydrostatic pressure
of mud in small increments by the U-tube technique until the pipe is free.
A variation of the U-tube method is to pump water into both the annulus and the drillpipe to
reduce hydrostatic pressure to a value equal to or just greater than the formation pressure.
This method is best illustrated by an example.
Example : : Simplified U-Tube Method
The following data refer to a differentially stuck pipe at 11,400 ft:
Formation pressure = 5,840 psi
Intermediate casing = 9.625 in, 40# at 10,600 ft
Drillpipe = OD /ID = 5/4.276 in
Mud density = 12.3 ppg
It is required to reduce the hydrostatic pressures in the drillpipe and the annulus so that both
are equal to the formation pressure.
Calculate the volumes of water required in both the annulus and the drillpipe, assuming that
the density of saltwater = 8.65 ppg.
Solution
Annulus Side
Assume the height of water in the annulus to be Y.
Required hydrostatic pressure at stuck point = 5,840 psi or
5,840 = 0.0.52x 8.65x Y + 0.052x 12.3x (11,400-Y)
Y = 7,647 ft (length of water column)
Required volume of water in annulus
= annular capacity between drillpipe and 9.625" casing x height of water
= 0.0515 (bbl/ft) x 7,6476
= 393.8 bbl
Hence, pump 393.8 bbl of water into the annulus to reduce the hydrostatic pressure in the
annulus to 5,840 psi at the stuck point. When 393.8 bbl of water is pumped into the annulus,
the drillpipe is still filled with the original mud of 12.3 ppg having a hydrostatic pressure at
the stuck point of (0.052x12.3 x 11,400) = 7,291 psi. Thus, a back-pressure equivalent to
7,291 – 5840= 1,451 psi will be acting on the annulus and will be attempting to equalise
pressures by back-flowing water from the annulus.
In order to contain the 393.8 bbl of water in the annulus, the drillpipe must also contain a
column of water equal in height to that in the annulus.
Thus,
volume of water required in drillpipe to prevent back-flow from annulus
= capacity of drillpipe x height of water = 0.0178 (bbl/ft) x 7,647 ft = 136 bbl
Balancing of the columns of water in the drillpipe and in the annulus can be achieved as
follows: (a) circulate 393.8 bbl of water down the annulus; (b) circulate 136 bbl of water
down the annulus; (c) circulate 136 bbl of water in the drillpipe to remove 136 bbl of water
from the annulus and to reduce the hydrostatic pressure in the drillpipe to 5,840 psi. At this
stage the hydrostatic pressure in the well is equal to the formation pressure of 5,840 psi.
If the well should kick during the operation, reverse-circulate down the annulus using the
12.3 ppg (i.e. original density) mud to recover all the water from the drillpipe. Then circulate
in the normal way through the drillpipe using 12.3 ppg mud until all the water is removed
from the annulus.

HOLE PROBLEMS lec ( 1 )

 IDENTIFICATION OF HOLE Problem
An event which causes the drilling operation to stop is described as a Non-Productive Time
(NPT) event. Pipe sticking and lost circulation are the two main events which cause NPT in
the drilling industry. Well kicks, of course, require operations to stop and when they occur
can result in a large NPT. At the time of writing this book, the average NPT in the drilling
industry is 20%.
There are many events which cause NPT in the drilling industry: see Chapter 15 for
details.Hence rather than detail every minor hole problem that has ever been recorded, this
chapter will deal with the main problems normally encountered while drilling. These
problems are: differential sticking, mechanical sticking and lost circulation. There will also
be a discussion of other miscellaneous problems.
1.1 PIPE STICKING
When the pipe becomes stuck, there are two key actions that will best influence the chance
of freeing the pipe:
• Determination of the cause of the stuck pipe incident.
• The initial response of the Driller and subsequent actions taken.
During the earliest stages of trying to free the pipe, the Drilling Supervisor should collate all
the relevant information and determine what caused the pipe to stick. This may well be
obvious from the well conditions that existed before the pipe became stuck. An incorrect
assessment of the cause of pipe sticking problem will reduce the chance of freeing the stuck
pipe.





There are basically two mechanisms for pipe sticking:
1. Differential Sticking
2. Mechanical Sticking
Mechanical sticking can be caused by:
• Hole pack off or bridging, or

• Formation and BHA (wellbore geometry)
Table 12.1 gives a summary of the pipe sticking mechanisms and their most common
causes.


2 - D. . I.F . F. E. .R . E. N. .T . I.A . L. . S. T. .I C. .K . I. N. .G
2.1 CAUSES OF DIFFERENTIAL STICKING
During all drilling operations the drilling fluid hydrostatic pressure is designed and
maintained at a level which exceeds the formation pore pressure by usually 200 psi. In a
permeable formation, this pressure differential (overbalance) results in the flow of drilling
fluid filtrates from the well to the formation. As the filtrate enters the formation the solids in
the mud are screened out and a filter cake is deposited on the walls of the hole. The pressure
differential across the filter cake will be equal to the overbalance.
When the drillstring comes into contact
with the filter cake, the portion of the
pipe which becomes embedded in the
filter cake is subjected to a lower
pressure than the part which remains in
contact with the drilling fluid. As a
result, further embedding into the filter
cake is induced.
The drillstring will become
differentially stuck if the overbalance
and therefore the side loading on the
pipe is high enough and acts over a
large area of the drillstring. This is
shown diagrammatically in Figure
12.1.
The signs of differential sticking are the clearest in the field. A pipe is differentially stuck if:
1. drillstring can not be moved at all, i.e. up or down or rotated

2. circulation is unaffected
Mathematically, the differential sticking force depends on the magnitude of the overbalance
and the area of contact between the drillpipe and the porous zone.Hence
Differential force = (mud hydrostatic – formation pressure) x area of contact
Hence for the data shown in Figure 12.2, and assuming the formation contacts only 4" of the
drillpipe perimeter, then the differential force is given by:
Differential Force = (5000-4000) psi x 4 x 00 = 1,200,000 lb
A more accurate form of the above equation contains a term for the friction factor between
the drillstring (steel) and the filter cake is given in Equation (12.1).
The force required to free a differentially
stuck pipe depends upon several factors,
namely:
1. The magnitude of the
overbalance. This adds to any side
forces which already exist due to
hole deviation.
2. The coefficient of friction
between the pipe and the filter
cake. The coefficient of friction
increases with time, resulting in
increasing forces being required
to free the pipe with time. Hence, when differentially stuck, procedures to free the
pipe must be adopted immediately. Figure 12.3 shows the coefficient of friction vs.
time for a bentonite filter cake which shows a 10 fold increase in under 3 hours







The surface area of the pipe embedded in
the filter cake is another significant factor.
The greater the surface area, the greater
the force required to free the pipe.
Thickness of filter cake and pipe diameter
will obviously have a great effect on the
surface area. It is for reasons of reducing
available surface area that spiral drill
collars are often specified
when drilling sections which exhibit the
potential for differential sticking
problems.
Statistically, differential sticking is found
to be the major cause of stuck pipe
incidents, hence great care should be taken
in the planning phase to minimise the overbalance wherever possible. However, in certain
circumstances, drilling with minimum overbalance is not be possible, as is the case for large
gas reservoirs (e.g. the Morecambe Field in the UK) where the pressure differential across
the reservoir starts at the minimum overbalance (200 psi) and increases substantially with
depth to a maximum of 1300 psi. In these cases, strict adherence to precautionary drilling
practices and good communication between personnel will help reduce the incidence of
stuck pipe.