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8/9/2019 Stuck Pipe and Filter Cake

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Hanna i s a petro leum engineer in the Material s Acquisiti on and Forecast ing Unit of

the Drilling and Workover Services Department. Having joined Saudi Aramco in 1991,

he has 28 years’ combined experience in drilling operations, drilling engineering and

drilling materials in the United States, Europe, Middle East, Asia and North Africa.

Hanna holds a bachelor ’s degr ee from the Universi ty of Zagreb in Croat ia, a master’s

degree from Tulane University in New Orleans, and a Ph.D. from Kennedy-Western

University in Boise, Idaho — all three in petroleum engineering. He has published and

presented numerous technical and professional papers.

A B S T R A C T

There are many causes of pipe sticking. It is desirable to identify the

type of sticking so that the most effective method of recovery may be

used. By understanding the causes of pipe sticking and implementing

good drilling practices, such as good mud and filter cake properties,

pipe and drill string movement, wiper trips, taper type and spiral

bottom hole assembly, controlling penetration rate and minimizing

contact area, the sticking problems can be reduced or completely

eliminated, resulting in enormous savings.

This paper describes the effect of filter cake thickness on the

contact area between pipe and filter cake. It computes the amount of

sticking force and the required pulling force to free the pipe. It also

compares the sticking force required to free the pipe with and without

using casing centralizers.

By implementing a simple calculation method and using developed

tables for determining the pipe/filter cake contact area, the force

required for pulling the pipe free, including the calculated pipe body

and joint strength safety factors, can be determined.

CAUSES O F PIPE STICKING AND

EFFECT O F FILTER CAKE

THICKNESS ON STICKING FORCE

by Iskander S. Hanna


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S A U D I A R A M C O J O U R N A L O F T E C H N O L O G Y • W IN T E R 1 9 9 8 /1 9 9 9 29

DISCUSSION

Let us visualize the conditions in the rock surrounding the bore-

hole. When a well is drilled with rotary tools and a drilling mud,

the usual practice is to maintain the weight of the mud at such a

value that the hydrostatic pressure of the mud column exceeds the

pressure of the fluids in the formations penetrated.

Keeping the differential pressure toward the formation prevents

the formation fluids from flowing into the wellbore causing the

well to blowout. However, such a drilling practice usually alters the

fluid content of the formation near the wellbore because the fil-

trate from the mud displaces some of the original fluids in the

pores of the rock by a process known as invasion.

Most water-base muds contain solids in suspension and chemi-

cals in solution. When the mud tries to flow into the pores of the

wellbore rock, only the filtrate enters leaving a deposit of mud

cake on the face of the rock in the borehole. The mud cake left in

the borehole may be thick or thin, tough or weak depending on

the type of the mud system.

Lowering the water loss of the drilling fluid will aid in the pre-

vention of sticking. Use of low water loss muds reduces the initial

contact area because these muds have a thin, hard filter cake, com-

pared to a thick, soft filter cake developed by a high water loss

mud. The pipe circumference cannot be embedded as deeply, and

therefore the sticking force is reduced (fig. 1). Moreover, low water

loss muds have a reduced filtration rate, which reduces the rate of

deposition of solids along the pipe-cake interface, minimizing the

increase in the friction coefficient. Reducing the friction coefficient,

or the “stickiness” of the mud, affects the sticking.

The friction controls the ease with which the pipe can be

dragged across the mud cake. Additives, such as oil or lubricity

agents, can reduce the cake friction.

The potential effect of the filter cake on the contact area is

critical. The area of contact may be more than doubled by thick-

ening the filter cake. This is the prime reason for controlling the

high-temperature, high-pressure filtration rate. The thickness of

the filter cake is the primary concern.Filter cakes during normal drilling generally reach an equilibrium

thickness. This means that the rate of erosion by the circulating

fluid equals the rate of deposition of new solids in the filter cake.

This concept of cake erosion shows the importance of making

short trips during long bit runs.

There are many causes of pipe sticking. It is desirable to identify

the type of sticking so that the most effective method of recovery

may be used.

By understanding the causes of pipe sticking and implementing

good drilling practices such as

1. Good mud and filter cake properties,

2. Pipe and drill string movement,

3. Wiper trips every ±500 ft,

4. Taper type and spiral bottom hole assembly,

5. Controlling penetration rate and

6. Minimizing contact area,

sticking problems can be reduced or completely eliminated.

The depth of invasion is influenced by several factors. These

factors are:

Water loss of the mud

The higher the water loss the greater the invasion.

Differential pressure

The differential pressure from mud column to formation usually

has some effect on the extent of invasion.

Time

The length of time the formation has been exposed to the mud

column is one of the important factors controlling invasion. The

longer it is exposed to the mud column, the greater a formation

will invade.

Mud Filter Cake

Mud Filter Cake

Mud Filter Cake

High Fluid Loss Mud

Low Fluid Loss Mud

Formation

Mud

Drill Pipe

or

Drill Collar

Fig. 1. Effect of mud filter cake thickness on initial contact area


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Porosity

A high porosity rock will invade less deeply than a rock with

lower porosity.

Permeability

Usually the permeability of the mud cake is so low that it controls

the flow of filtrate into the formation.

TYPES OF FORMATION PRESSURE

The term formation pressure is the pressure in the formation caused

by the hydrostatic head of the fluid in the pore space (IADC 1980

and McLure 1983). In a closed formation, this pressure is caused

by the fluid bearing the weight of the overburden rocks. Formation

fluid pressures are divided into:

Normal formation pressure

The normal formation pressure is assumed to be the pressure

caused by the formation fluid.

Abnormally high formation pressure

Formations that have abnormally high pressure are considered to

be closed reservoirs.

Subnormal formation pressure

If the formation pressure gradient is less than the calculated normal

hydrostatic pressure, the pressure is said to be subnormal.

PIPE STICKING

Common causes

There are many causes of pipe sticking. It is desirable to identify

the type of sticking so that the most effective method of recovery

may be used. Some common types of pipe sticking are:

Mechanical sticking

Pipe may be mechanically stuck by packers, anchor-catchers, junk

lost in the hole, multiple strings which have wrapped around each

other, and crooked pipe that has been dropped or corkscrewed.

When casing collapses, the tubing is stuck in the collapsed section.

Mud sticking

Usually caused by the settling out of solids in the mud. Casingleaks can allow shale and mud to enter the casing and stick the

tubing and other equipment. Cuttings produced when drilling a

well must be circulated out sufficiently to keep the hole clean;

otherwise, they will accumulate and cause sticking. Insufficient

mud systems are frequently the cause of sticking in drilling wells.

In some cases, wells have been drilled with clear water, and any

mud used is that which was produced by cuttings. This “native

mud” can cause sudden sticking over a long interval.

Key seat sticking

In deviated wells, the subsequent rotation of the pipe and particu-

larly the hard-banded tool joints in the area of the “dogleg” wear

a lot in the wellbore that is smaller than the gauge hole. When

pulling the pipe out of the hole, the larger drill collars are pulled

up into the key seat and stuck. Drillers usually pull harder as they

observe the pipe tending to stick. This, of course, makes the

situation worse.

Cement sticking

Cement sticking can occur due to mechanical failure in equipment,

a leak, human error or intentional cementing in an attempt to con-

tain a blowout or correct lost circulation. Many times when

cement sticking occurs, premature or flash setting is blamed. The

cuttings produced in drilling cement will readily stick the pipe if

they are allowed to settle out of the fluid.

Blowout stickingWhen formation pressure exceeds the hydrostatic pressure of the

mud, it causes shale, sand, mud or other formation materials and,

in some cases, even drill pipe protector rubbers, to be blown up

the hole, which sometimes bridges over and sticks the pipe.

Sloughing hole sticking

Shale sections which swell can break off into the hole, lodging

around the tool joints, drill collars or the bit, causing the drill

string to become stuck.

Undergauge hole sticking

A bit that has become worn under size by an abrasive formation

may cause this problem. Also, an expanding formation such as salt

flow, shale deforming or swelling of clay may cause this problem.

Lost circulation sticking

This problem occurs in formations ranging from shallow unconsol-

idated sands to formations that may be fractured by excessive mud

weights used. Lost circulation may be controlled by the use of the

proper drilling fluid even after the drill string has become stuck

and is being washed over.

Differential pipe stickingThis is caused by a high hydrostatic pressure creating differential force

that holds the pipe in a thick filter cake across a permeable zone.

Differential sticking occurs only across a permeable zone, such

as sand, and the friction resistance may be a function of the filter

cake thickness. The sticking force can be calculated by the

following equation:

Fs = ∆P • Ac • Cf

30 S A U D I A R A M C O J O U R N A L O F T E C H N O L O G Y • W IN T E R 1 9 9 8 /1 9 9 9


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The total pulling force necessary to pull the pipe free is calculated

as follows:

Ft = Fs + Wtb + Drag

Area of contact versus filter cake thickness

The filter cake thickness, in thirty-seconds of an inch (nearest 1/32

inch), is determined from the API fluid loss run for 30 minutes.

The calculations in table 1 are derived from fig. 5 and can be used

to determine the contact area between the pipe and the filter cake

(i.e., length of sticking line in square inches per inch of pipe

length). Fig. 8 shows the equations that were derived and used

as the basis for table 1. It should be noted from table 1 that for a

9-5/8 inch × 12.25 inch configuration, by misinterpreting the filter

cake thickness of 2/32 inch instead of 1/32 inch (for example), the

contact area in square inches per inch of pipe length is increased

from 2.3745 inches to 3.3595 inches, a difference in cake thickness

of 1.0205 inch or a 29% increase in contact area. It has been general

practice to report the filter cake thickness as 2/32 inch. However,

the above calculations show the importance of measuring the filter

cake thickness accurately and the effect of the cake thickness on

the sticking force calculations. Therefore, it is very important to

measure the filter cake thickness as accurately as possible.

Mud properties

Mud weight is an important factor for differential sticking.

Reducing the mud weight to a safe level will minimize the differ-

ential pressure. However, the mud weight can be reduced only a

certain amount and still maintain pressure control of the well

(Gatlin 1960).

Thickness of Filter Cake (In) t = t 1/32″ 2/32″ 3/32″ 4/32″ 5/32″ 6/32″ 7/32″ 8/32″ 12/32″ 16/32″ 24/32″ 32/32″ Thickness of Filter Cake (In) t = t 0.0313 0.0625 0.09375 0.125 0.1563 0.1875 0.2188 0.25 0.375 0.5 0.75 1

Size of Pipe (In) D1 = D1 9.625 9.625 9.625 9.625 9.625 9.625 9.625 9.625 9.625 9.625 9.625 9.625

Size of Hole (In) D2 = D2 12.25 12.25 12.25 12.25 12.25 12.25 12.25 12.25 12.25 12.25 12.25 12.25

a = (D2/2) - t a 6.0937 6.0625 6.03125 6 5.9687 5.9375 5.9062 5.875 5.75 5.625 5.375 5.125

b = D1/2 b 4.8125 4.8125 4.8125 4.8125 4.8125 4.8125 4.8125 4.8125 4.8125 4.8125 4.8125 4.8125

c = (D2-D1)/2 c 1.3125 1.3125 1.3125 1.3125 1.3125 1.3125 1.3125 1.3125 1.3125 1.3125 1.3125 1.3125

COS A = (b2+c2-a2)/(2xbxc) 0.9698 0.939703154 0.909786642 0.8801 0.8504 0.821 0.7916 0.7625 0.6475 0.5349 0.3172 0.1095

A = Angle in Degrees 14.1169 19.9982 24.5241 28.3456 31.7448 34.815 37.6647 40.3149 49.6466 57.6629 71.5063 83.6847

A = Angle in Rad. 0.2467 0.349035052 0.428026576 0.5389 0.5541 0.6076 0.6574 0.7036 0.8665 1.0064 1.248 1.4606

Width of Contact (In) X = A x 2 x (D1/2) 2.3745 3.359462376 4.119755797 5.1867 5.3327 5.8485 6.3272 6.7724 8.34 9.6867 12.012 14.058

Thickness of Filter Cake (In) t = t 1/32″ 2/32″ 3/32″ 4/32″ 5/32″ 6/32″ 7/32″ 8/32″ 12/32″ 16/32″ 24/32″ 32/32″

Thickness of Filter Cake (In) t = t 0.0313 0.0625 0.09375 0.125 0.1563 0.1875 0.2188 0.25 0.375 0.5 0.75 1

Size of Pipe (In) D1 = D1 7 7 7 7 7 7 7 7 7 7 7 7

Size of Hole (In) D2 = D2 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5

a = (D2/2) - t a 4.2187 4.1875 4.1563 4.125 4.0937 4.0625 4.0312 4 3.875 3.75 3.5 3.25

b = D1/2 b 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5

c = (D2-D1)/2 c 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75

COS A = (b2+c2-a2)/(2xbxc) 0.8862 0.8396 0.7933 0.7472 0.7015 0.6563 0.6112 0.5667 0.3917 0.2222 0.1 0.4


A = Angle in Rad. 0.4817 0.5743 0.6546 0.7269 0.7933 0.855 0.9132 0.9683 1.1684 1.3467 1.4706 1.1593

Width of Contact (In) X = A x 2 x (D1/2) 3 .372 4.02 4.5821 5.0885 5.5532 5. 9847 6. 3924 6. 7784 8.1785 9.4269 10.2944 8.115

Thickness of Filter Cake (In) t = t 1/32″ 2/32″ 3/32″ 4/32″ 5/32″ 6/32″ 7/32″ 8/32″ 12/32″ 16/32″ 24/32″ 32/32″

Thickness of Filter Cake (In) t = t 0.0313 0.0625 0.09375 0.125 0.1563 0.1875 0.2188 0.25 0.375 0.5 0.75 1

Size of Pipe (In) D1 = D1 7.25 7.25 7.25 7.25 7.25 7.25 7.25 7.25 7.25 7.25 7.25 7.25

Size of Hole (In) D2 = D2 9.875 9.875 9.875 9.875 9.875 9.875 9.875 9.875 9.875 9.875 9.875 9.875

a = (D2/2) - t a 4.9062 4.875 4.8438 4.8125 4.7812 4.75 4.7187 4.6875 4.5625 4.4375 4.1875 3.9375

b = D1/2 b 3.625 3.625 3.625 3.625 3.625 3.625 3.625 3.625 3.625 3.625 3.625 3.625

c = (D2-D1)/2 c 1.3125 1.3125 1.3125 1.3125 1.3125 1.3125 1.3125 1.3125 1.3125 1.3125 1.3125 1.3125

COS A = (b2+c2-a2)/(2xbxc) 0.9676 0.9356 0.9037 0.8719 0.8404 0.8091 0.778 0.7471 0.6256 0.5074 0.2808 0.0673


A = Angle in Rad. 0.2552 0.361 0.4425 0.5117 0.5728 0.6282 0.6794 0.7271 0.8949 1.0386 1.2862 1.5034

Width of Contact (In) X = A x 2 x (D1/2) 1.8499 2.6171 3.2081 3.7097 4.1531 4. 5541 4. 9254 5.2712 6.4879 7.5302 9.3248 10.8998

TABLE 1.CONTACT AREA VERSUS FILTER CAKE THICKNESS, SQUARE INCHES PER INCH OF PIPE LENGTH

Table 1 is continued on the following page


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Filter cake property

When evaluating mud filtration, three stages of filtration should be

evaluated (Gatlin 1960):

1. The initial surge period: before any appreciable cake is

formed, Vs + Vx (fig. 2).

2. The transition period: after a filter cake is initiated but before

it becomes uniform, i.e., the period during which the cake

surface is irregular and is under unequal pressure gradients at

different points.

3. The constant pressure gradient period: filtration volume

varies linearly with the square root of time. Quantitative

analysis of the water loss in each stage is given by the follow-

ing equation:

t = m • V2 + n • V

Rearrangement of this equation is useful for plotting purposes:

t/V = m • V + n

A plot of t/V vs. V becomes linear when m becomes constant in

stage 3 of the filtration process (fig. 3). The surge loss Vs is obtained

as the magnitude of V when t/V=

0. Careful analysis of the originaldata will also allow determination of the corresponding surge ts,

where ts = t – t′ (see below). Since stage 3 is completely governed

by the permeability of the filter cake, the above equation may be

rewritten in terms of the surge corrected volume V′ and time t′:

t′ /V′ = m • V

Where

t′ = t − ts

V′ = V − Vs


Thickness of Filter Cake (In) t= t 1/32″ 2/32″ 3/32″ 4/32″ 5/32″ 6/32″ 7/32″ 8/32″ 12/32″ 16/32″ 24/32″ 32/32″

Thickness of Filter Cake (In) t= t 0.0313 0.0625 0.09375 0.125 0.1563 0.1875 0.2188 0.25 0.375 0.5 0.75 1

Size of Pipe (In) D1= D1 5 5 5 5 5 5 5 5 5 5 5 5

Size of Hole (In) D2= D2 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5

a = (D2/2) - t a 4.2187 4.1875 4.1563 4.125 4.0937 4.0625 4.0312 4 3.875 3.75 3.5 3.25

b = D1/2 b 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5

c = (D2-D1)/2 c 1.75 1.75 1.75 1.75 1.75 1.75 1.75 1.75 1.75 1.75 1.75 1.75

COS A= (b2+c2-a2)/(2xbxc) 0.9697 0.9397 0.91 0.8804 0.851 0.8219 0.7929 0.7643 0.6518 0.5429 0.3357 0.1429

A= Angle in Degrees 14.1397 19.9934 24.4973 28.3145 31.684 34.7271 37.5405 40.1565 49.3236 57.1217 70.384 81.7868

A= Angle in Rad. 0.2468 0.349 0.4276 0.4942 0.553 0.6061 0.6552 0.7009 0.8609 0.997 1.2284 1.4274

Width of Contact (In) X= A x 2 x (D1/2) 1 .2339 1.7448 2.1378 2.4709 2.7665 3.0305 3.276 3.5043 4.3043 4.9848 6.1422 7. 1372

Thickness of Filter Cake (In) t= t 1/32″ 2/32″ 3/32″ 4/32″ 5/32″ 6/32″ 7/32″ 8/32″ 12/32″ 16/32″ 24/32″ 32/32″


Size of Pipe (In) D1= D1 5 5 5 5 5 5 5 5 5 5 5 5

Size of Hole (In) D2= D2 12.25 12.25 12.25 12.25 12.25 12.25 12.25 12.25 12.25 12.25 12.25 12.25

a = (D2/2) - t a 6.0937 6.0625 6.03125 6 5.9687 5.9375 5.9062 5.875 5.75 5.625 5.375 5.125

b = D1/2 b 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5

c = (D2-D1)/2 c 3.625 3.625 3.625 3.625 3.625 3.625 3.625 3.625 3.625 3.625 3.625 3.625

COS A= (b2+c2-a2)/(2xbxc) 0.9789 0.958 0.9371 0.9164 0.8957 0.8752 0.8548 0.8345 0.7543 0.6759 0.5241 0.3793


A= Angle in Rad. 0.2058 0.2909 0.3565 0.4119 0.4608 0.5049 0.5457 0.5836 0.7162 0.8287 1.0191 1.1817

Width of Contact (In) X= A x 2 x (D1/2) 1.0289 1.4547 1.7825 2.0593 2.3038 2.5246 2.7285 2.918 3. 581 4.1433 5.0955 5. 9087

Thickness of Filter Cake (In) t= t 1/32″

2/32″

3/32″

4/32″

5/32″

6/32″

7/32″

8/32″

12/32″

16/32″

24/32″

32/32″


Size of Pipe (In) D1= D1 5 5 5 5 5 5 5 5 5 5 5 5

Size of Hole (In) D2= D2 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5

a = (D2/2) - t a 8.7187 8.6875 8.6563 8.625 8.5937 8.5312 8.5 8.375 8.25 8 7.75

b = D1/2 b 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5

c = (D2-D1)/2 c 6.25 6.25 6.25 6.25 6.25 6.25 6.25 6.25 6.25 6.25 6.25 6.25

COS A= (b2+c2-a2)/(2xbxc) 0.9825 0.9651 0.9478 0.9305 0.9133 0.8961 0.879 0.862 0.7945 0.728 0.598 0.472


A= Angle in Rad. 0.1873 0.2649 0.3245 0.375 0.4196 0.4598 0.497 0.5316 0.6526 0.7554 0.9298 1.0792

Width of Contact (In) X= A x 2 x (D1/2) 0.9365 1.3244 1.6225 1.8751 2.098 2.2992 2.4851 2.658 3.2631 3.777 4.649 5.3962

TABLE 1.

continued from previous page


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A plot of t′ /V′ vs. V′ becomes linear when m = constant. Hence

the filtration loss during stage 2, Vx, may be obtained as the linearly

extrapolated intercept at t′ /V′ = 0 (fig. 3). The importance of this

procedure lies in the fact that additives which improve stage 3

behavior do not necessarily improve losses during other stages.

The surge loss of stage 1 is dependent on the rapidity with which

the mud solids bridge surface and internal pore openings. A mud

which contains properly sized solids for a particular sand may be

expected to bridge more quickly and efficiently than one which is

deficient in some critical sizes.

Area of contact between filter cake and pipe

The contact area between the filter cake and pipe is an important

factor. The area of contact represents the total area of the pipe

covered by filter cake across which the pressure differential is

effective. The area of contact is affected by the following

(Stewart and Moore 1986):

1. Length of sticking interval2. Hole size and pipe size

3. Thickness of the filter cake

4. External stabilization of the pipe

Pipe movement

Moving the pipe at all times will reduce the sticking, since it prevents

the pipe from being embedded in the wall cake. In addition, quick

action after the pipe becomes stuck is essential to prevent further

sticking in other zones that would not ordinarily cause problems.

Amount of differential pressure

Differential pressure exists when the equivalent circulating density

(ECD) is greater than the formation pore pressure. One method

utilized to minimize this effect is to drill with minimum mud

weights. The problem of minimizing the differential pressure is

often complicated by long sections of open hole, where the forma-

tion pore pressures are substantially different. For this reason, a

given mud weight may be necessary to control the pore pressure

in one open formation, and this will impose a large pressure

differential across another open formation.

Differential pressure sticking is recognized as a potential

problem when the differential pressure reaches a given level in a

specific area. Field studies have been used to establish values for

the amount of differential pressure that can be tolerated before

sticking occurs. These values are as follows (Stewart):

Across normal pressured zones: 2,000 to 2,400 PSI.

Across abnormal pressured zones: 3,100 to 3,300 PSI.

However, wells have been drilled across subnormal pressured

zones (depleted sands) with a differential pressure as high as 4,720

PSI, successfully (Hanna and Hollister 1989).

The maximum overbalance pressure depends on the type of the

wellbore as shown in fig. 4. Straight holes can tolerate higher over

balance pressure than deviated holes.

Bottom-hole assembly

The bottom-hole assembly shape is a very important parameter

and is one that can be changed easily. Large, externally flush drill18.0

16.0

14.0

12.0

10.0

8.0

6.0

4.0

2.0

0

Vc @ 30 min.

Vs + Vx

V ,

F i l t r a t e V o l u m e ,

C C

t 1 Seconds

0 10 20 30 40 50 60

Fig. 2. Standard method of obtaining API fluid loss. Corrected volume Vc

is commonly reported. Vs + Vx = initial spurt or surge correction. After

Slusser, Glenn and Huitt; courtesy AIME.

160

150

140

130

120

110

100

90

80

70

60

50

40

30

20

10

0

T i m e / F i l t r a t e V o l u m e S e c o n d s / C C

Filtrate Volume, CC

0 2 4 6 8 10 121 3 5 7 9 11 13 15 1614

Vx

Vs

t’/V’ vs V’ t/V vs V

Fig. 3. Method of plotting filtration data. Vs, Vx and Vc are determined as

shown. After Slusser, Glenn and Huitt; courtesy AIME.


7/14

collars represent the ideal type of equipment for differential pressure

sticking. Special drill collar configurations have been used. Some of

these are: spiral collars, with circulation grooves in the external

surface of the drill collars; square drill collars; and shouldered drill

collars. Spiral heavy weight drill pipe has been also used. The

effect of the special drill collars is to reduce substantially the area

of wall contact. The heavy weight drill pipe has reduced substan-

tially the differential pressure sticking problem, particularly in

directional wells (Stewart; McKeown and Williamson 1986).

Length of the sticking interval

The length of the sticking interval is a fixed parameter, since

there is no control of the permeable zone that will be penetrated.

Therefore, this factor cannot be changed.

Control drilling

It is highly advantageous to control the instantaneous penetration

rate at 100 ft/hr (30.5 m/hr) maximum, in a 12-1/4″

hole, in thepressure depleted interval, and pump at the maximum rate possible

to maintain a low percentage of native solids in the annulus (2% or

less). A higher pump rate will add additional pressure on the

formation, due to friction in the annulus, and at the same time will

keep the annulus clean and will also keep the pressure imposed on

the formation due to the solids buildup in the annulus at a minimum

level. The bottom line is to keep the hole clean.

The following equation can be used to calculate the maximum

allowable rate of penetration based on the pump rate and the

desired percentage of native solids in the annulus (Mobil 1989).

ROP(ft/hr) = Q × f

Dh2 × (1− f)

1470

Hole stability/deviation

Formations at depth exist under a state of compressive in-situ stress.

When a well is drilled, the rock surrounding the borehole must

support the load that was previously taken by the removed rock.

As a result, the hole produces an increase in the stress around the

hole (a stress concentration). If the rock is not strong enough, the

borehole will fail (Cheatham 1984). To keep the rock from failing,

1. a mud is selected that minimizes the weakening of the rock;

and

2. the pressure in the wellbore is increased by weighting up the

mud and adding filtrate control additives so that the wellbore

pressure carries some of the load imposed on the wellbore

wall by the in-situ stresses (Bradley 1979).


0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

T r u e V e r t i c a l D e p t h ( f t )

45°Holes

Max PPG

Diff

30°Holes

Max PPG

Diff

Straight

HolesMax PPG

Diff

Maximum

Overbalance(PPG)

0 1 2 3 4 5 6 7

1 2 3 4 5 6 7

8

Maximum Overbalance Pressure x 1000psi

Rule of Thumb

Fig. 4. Guidelines for maximum overbalance in various type wellbores

(high permeable sands — soft rocks)

2 in

2 in

40 ft

40 ft

Contact Area = (40′ x 12) x (2″ ) = 960 sq. in.

Fig. 5. Pipe/formation contact area


8/14


An inclined hole requires higher mud weight than a vertical one

to prevent wellbore collapse (Cheatham 1984). Bradley (1979)

found, in one example, that increasing the hole angle from 0 to

60° requires that the mud weight be increased by 2.5 lb/gal (0.30

g/cm3) to prevent collapse of the hole. Compared with a vertical

hole, a steeply inclined hole has reduced ability to withstand mud

pressure without fracture initiation and requires greater mud

pressure to prevent hole collapse. Based on the above, it is recom-

mended to drill depleted sand zones with straight hole rather than

directional hole. Straight holes require less mud weight for stability

control than directional holes, and therefore less differential pressure.

If we can reduce or minimize one or all of the components at

the right side of the equation below, then the sticking force will be

reduced, too.


In reality, the pressure differential, ∆P, between the hydrostatic

head of the mud and the formation pore pressure can only be

reduced to a minimum safe level. Sometime, this differential pres-

sure cannot be reduced due to hole condition and the presence of

formations with different pore pressures in the same open hole.

The friction factor, Cf, can be reduced by using oil-base muds.

However, oil-base muds are very expensive. The friction factors

for different water-base mud systems at different mud weights are

given in table 2.

A better approach to this problem is to reduce or minimize the

contact area between the casing and wellbore wall.

A 40-ft joint of casing when embedded for two inches in a filter

cake (fig. 5) will have a contact area of:

(40′) × (12) × (2″ ) = 960 sq. in.

However, when two centralizers, for example, are used on the same

joint, one at each end (figs. 6 and 7), then the contact area of the

centralizers with the borehole wall will be:

(2 Bows per Cent.) × (2 Cents.) = 4 Bows Contact

If each bow is 1.5 inches wide and 24 inches long, then the

contact area “A” will be equal to:

A = (4 Bows) × (1.5″ wide) (24″ long) = 144 sq. in.

By using centralizers we can reduce the contact area by:

(960 − 144/960) × 100 = 85%

Note: If only one centralizer is needed to give the desired standoff,

then the contact area of one centralizer will be:

144/2 = 72 sq. in., or a 92.5% reduction in the contact area.

A detailed problem on the effect of using centralizers on the stick-

ing force is given under “Problem: Differential Pressure Sticking.”

Let us now take a field example to calculate the effect of the

contact area on the sticking force:

Example

A 10,000 ft of 5”, 19.5 lb/ft drill pipe is imbedded for 3” in the wall

cake over a 25-foot section of sand zone, with a pressure differential

of 1,600 PSI, and a friction coefficient of 0.26. If the upward drag

in this well is 35,000 lbs, calculate the total pulling force to free

this pipe.

Sticking force, Fs:


Fs = 1600 × (3 × 25 × 12) × 0.26 = 374,400 lbs

Total pulling force to free, Ft:

Ft = Fs + Wtb + Drag

Wtb = [(65.45 − 10) / 65.45] • 10,000 • 19.5

Wtb = 165,206 lbs

Ft = 374,400 + 165,206 + 35,000 = 574,606 lbs

Normally the sticking occurs when the drill pipe is not in motion,

and usually full or partial circulation can be accomplished. The

immediate step to be taken is to shut down the pump. Pump

Mud Type MW Friction Coefficient

FW Ligno 9.5 ppg 0.31 (16 hr @ 150°F)

SW Ligno 11.5 0.35 (16 hr @ 150°F)

SW Ligno 12.0 0.26 (without aging)

SW Ligno 17.0 0.29 (without aging)

KCl/Drisp N/A 0.34 (16 hr @ 150°F)

Oil-base,unwtd 7.0 0.09

Oil-base Mud 18.5 0.13

TABLE 2.MUD WEIGHT VS. FRICTION COEFFICIENT

Stand-Off (Sag Point)

Centralizer Centralizer

Centralizer Spacing

Casing

Formation

Formation

Fig. 6. Centralizer spacing showing sag point


9/14

pressure during circulation increases the wellbore pressure slightly.

Stopping this additional pressure may be enough to reduce the

force sufficiently that the pipe may be worked free.

F ISH ING

“Fishing” is a term used for procedures to free a stuck pipe or drill

collars, recover pipe twisted off or lost downhole, remove loose

junk, and recover or remove parted or stuck wireline (Gatlin 1960).

Although a fishing job is unwelcome, sometimes it is a neces-

sary procedure in both drilling and workover operations. A fishing

job is expensive and usually not in the budget, and the foreman

must see that it is performed in the proper way.

If none of the preceding methods is successful, it will be neces-

sary to part the pipe and either jar it or wash over. Ordinarily jars

are used if the stuck interval is short. If there is a great deal of pipe

to be freed, most operators will wash over.

Fishing is not an unusual practice, and is required to some

degree in about 20% of the wells drilled and about 80% of thewells that are worked over.

The cost of fishing, including the rig time used, is considerable;

therefore, care and judgment must be exercised.

Fishing tools and practices have been developed over the years,

making possible the correction of almost any downhole problem.

However, sometimes the cost may be prohibitive.

Fishing is not an exact science, and many times there is more

than one way to approach the problem. Personnel of fishing tool

companies have gained considerable experience by performing this

work constantly, whereas operating personnel are exposed to these

problems only occasionally. However, many operations personnel

are very familiar and experienced in fishing and stuck-pipe problems.

Planning a fishing job is the most important phase of the opera-

tion, and adequate planning can reduce cost. All personnel, such as

fishing tool operators, mud company personnel, rig personnel and

electric wireline company representatives, should be involved in

the discussion and the planning phase.

Economics of fishing

Fishing should be an economical solution to the problem in the

well. A shallow hole with little rig time and equipment can justify

only the cheapest fishing. When there is a large investment in the

hole and expensive equipment to be recovered, more time andexpense can be justified. An economic decision should be made

“to fish or not to fish; if so, for how long?”

Probability factors are used in determining the time to be spent

on a fishing job. These percentages must be derived from similar

situations. This sometimes may not be correct, as there are no two

fishing jobs exactly alike.

Decision trees with the associated costs should be established

for drilling and workover programs.

The best solution is good judgment, careful analysis of the

problem, and the skilled application of the decision insofar as the

rig and tools are concerned.

Avoiding hazards

There are many causes that contribute to a fishing job on drilling

and workover jobs, but the predominant one is “human error”

(Gatlin 1960).

There are some basic rules which should be followed during all

drilling and workover operations that become even more important

when fishing. Every effort should be made to recover something or

to improve the situation on each trip in the hole with the tools.

Misruns waste money, and there is the possibility of additional

mishaps on every trip in the hole.

Drawings showing dimensions should always be made of every-

thing that is run in the wellbore. Both the service company and the

operating company personnel must share this responsibility. Each

should make independent measurements and sketches.

For a large or unusual tool or downhole assembly being run, aplan should be formulated as to how it would be fished if it should


Open Hole

Casing

Contact area = 2 Bows per centralizer

Bow area = 1.5" x 24" = 36 sq. in.Total contact area per centralizer = 2 x 36 = 72 sq. in.

For two centralizers, the contact area = 2 x 72 = 144 sq. in.

Formation

Bow 1.5"

24"

Fig. 7. Centralizer bows contact area


10/14


become stuck or broken. Before you run the tool, ask: “Can this

tool be fished? Can it be washed over? If so, what size washpipe

can be run?”

Jars are run as insurance against sticking. If there is a reasonable

chance that the tool or assembly may get stuck, then jars run in

the string are appropriate and the costs are justified.

Mud and other well fluids should be conditioned and have the

desired properties prior to a trip in the hole with fishing tools. It

may be necessary to make a trip with a bit to condition the hole

and circulate out fill that has covered up the fish.

When fishing, consideration should be given to releasing or

recovering the fishing tools themselves should they become stuck

or the fish is pulled and the tool cannot be released. Ensure that

the fishing tool works properly with the fish in question on the

surface before running the tool downhole.

SOLUTIONS TO P IPE

STICKING PROBLEMS

Surge method

The surge or U-tube method of freeing the stuck pipe involves

displacing a portion of the mud system in the hole with a lighter

weight fluid and allowing the system to flow back to a balanced

position. This lighter fluid may be diesel oil, crude oil, water, nitro-

gen, gas or any fluid that is available with an appropriate weight.

When the fluid is flowed back, the fluid level in the annulus is

lower; therefore the hydrostatic pressure on the formation is

reduced. If this is sufficient to at least equal the formation pressure,

the string will come free. This method of freeing the pipe is safe

since the pressure can be reduced in several steps. The mud weight

itself is not reduced, and if a kick occurs, the fluid which was

flowed out of the annulus can control it.

Spotting fluid

If there is not sufficient reduction in pressure to free the pipe, then

usually it is advisable to spot a fluid across the stuck zone, which

will penetrate the filter cake and remove it.

The concept of spotting fluid(s) is similar to the oil-base invert

(water-in-oil) emulsion mud. Both are based on the osmotic pres-

sure concept. Oil-base mud and/or spotting fluid is very slick mud

in which the degree of inhibition is controlled by adjusting the

chloride content of the water phase. Chlorides slightly higher than

the chlorides in the water in the shale will inhibit the shales.

Chlorides much higher will remove the water from the shale,

which toughens the wall of the hole. Gauge holes are usually

drilled with invert emulsion oil mud because the shales are highly

inhibited. In the case of spotting fluid, the chloride content of the

water phase (internal phase) is mixed higher than the salinity of

the mud system. This difference in salinity will result in osmotic

pressure that will inhibit and toughen the mud filter cake. The end

result is that the filter cake will shrink, resulting in a smaller contact

area between the filter cake and the stuck pipe. Literature shows

that the osmotic pressure between salt-saturated calcium chloride

brine opposite fresh water shale at 25°C can reach up to 24,400

PSI (After Baroid (1977), table 2, courtesy of Baroid Petroleum

Services). Meanwhile, the osmotic pressure between salt-saturated

sodium chloride brine opposite fresh water shale at 25°C can reach

5,800 PSI. This makes the calcium chloride brine predominantly

used in oil-base muds and spotting fluids.

Diesel and crude oils are used most commonly with the proper

surfactant in the mixture. The most usual problem with this

method is that the operator will not spend enough time to allow

the filter cake to be removed. The freeing fluid is invariably lighter

than the mud in the hole, so there is going to be considerable

migration up the hole after it is spotted. It is necessary that a new

slug be spotted about every 30 minutes. At least eight hours should

be allowed for the procedure to take effect.

Torquing the pipe during this time is advisable and small

amounts of weight can be left on the stuck pipe if it is off bottom.

Drill stem test tool (DST)

This is one method of freeing differentially stuck pipe which is

used most effectively but has not been universally accepted

because of other inherent hazards of the operation (Kemp 1986).

Open-hole packers or test tools may be used to remove the

hydrostatic force from the stuck pipe and to free it the instant the

tool is set.

The purpose of the DST tool is to lower the hydrostatic pres-

sure around the fish enough to allow the formation pressure to

push the fish away from the wall. The fishing string consists of a

catching tool or screw-in sub on bottom, a perforated sub in case

the fish is plugged, bumper jars, packer and optional safety joint,

and jars above the test tool. A good packer seat must be selected.

By backing off the pipe string and spacing out the fishing string,

the test tool will be located in the appropriate zone. To operate

the tool, the string is run and the fish caught or screwed in. The

weight of the string is set down on top of the fish, which causes

the packer to expand and seal off. This separates the mud column

above the packer from the hole below, greatly reducing the hydro-

static head in the stuck section. As weight is applied to the string,

a bypass valve opens so that the pressure trapped below the packer

escapes into the drill string. The pressure in the formation immedi-ately pushes the stuck pipe away from the wellbore wall. As the

string is picked up, the packer unseats and contracts, the connecting

valve closes and the bypass valve opens. The fish may then be

pulled from the wellbore.

If none of the preceding methods is successful, it will be neces-

sary to part the pipe and either jar on it or wash over. Ordinarily,

jars are used if the stuck interval is short. If there is a great deal of

pipe to be freed, most operators will wash over.


11/14

DETERMINING THE STUCK POINT

Measuring stretch

When pipe becomes stuck, the first step is to determine at what

depth the sticking has occurred.

Stretch in pipe can be measured and calculation made to esti-

mate the depth to the top of the stuck pipe. If the length of stretch

in the pipe with a given pull is measured, the amount of the free

pipe can be calculated or determined from a chart.

First, mark a point at the rotary table level with the hook load

completely slacked off. Pull tension on the pipe at least equal to

the normal hook load (air weight) of the pipe prior to getting

stuck. Record the tension applied as a pulling force, F1, and

measure the stretch, S1, in the pipe in inches, due to the pulling

force F1.

Next, pull additional tension, which has been predetermined

within the range of safe tensional limits on the pipe. Record the

new pulling force, F2, and measure the stretch, S2, in inches,

which resulted due to the pulling force F2.The stuck pipe depth can be determined by using the

following equation:

Stuck Pipe Depth, D = 735 × 1,000 × W × ∆S

F2 − F1

Example

A 10,000 ft of 3-1/2”, 13.3 ppf drill pipe is stuck in hole. The fol-

lowing measurements were obtained for the purpose of calculating

the free point:

F1 = 133,000 lbs

F2 = 200,000 lbs

∆S = 4 ft

Determine the free point (at which depth the pipe is stuck):

D = 735 × 1,000 × 13.3 × (4 • 12)

200,000 − 133,000

D = 735,000 × 638.4 = 7,003.34 ft

67,000

STRETCH IN STEEL P IPE

Stretch, S, in tubing or casing can be calculated using the

following equation:

S = (Force) × ( Length)

(Steel Elasticity Factor) × (Cross Sect. Area)

or

S = F × L

E × A

Also, the length change due to temperature can be calculated usingthe following equation:

L = 0.0000069 × F × ∆T

and

F = 207 × A × ∆T

Example

If the stretch of 2,000 ft of 1.315″ tubing with ID = 1.049″ ,

(Cross-sectional area = 0.49 sq in), due to pull of 7,000 lbs is equal

to 11.42857 in, calculate the actual length and force changes due

to temperature change:

∆T = T2 − T1

∆T = 100 − 80 = 20 F

∆L = 0.0000069 × L × ∆T

∆L = 0.0000069 × 2000 × 20 = 0.276 ft


a = (D2/2) - t A1 = 180 - A Cos A = (b2 + c2 - a2) / 2 (b x c)

b = D1/2 c = (D2 - D1) / 2 D1 = Pipe OD

D2 = Hole ID t = Filter cake thickness

X = Pipe/filter cake sticking line length = A x 2 x (D1/2)

D1

D2

A1

A

b

ac

Filter

Cake

WellboreWall

X t

Pipe

Fig. 8. Calculations of contact area versus filter cake thickness


12/14


Total Stretch = 11.42857 + (0.276 × 12) = 14.74 in

Force due to temperature change, F:

F = 207 × A × ∆T

F=

207×

0.49×

20=

2,029 lbs

Stretch due to 2,029 lbs force, S:

S = 2029 × 2000 = 0.276 ft = 3.312 in

30,000 × 0.49

This length change due to temperature should be added to the

calculated stretch of the casing/pipe to better determine the stuck

pipe depth.

Buoyancy

When pipe is stuck, the buoyant forces are being exerted against

the stuck section, and therefore there is no effective buoyant force

at the surface. Immediately when the pipe is freed, the buoyant

forces are again in effect and are to be reckoned with accordingly.

This statement, of course, ignores the cumulative length of the tool

joints or couplings and the small hydrostatic forces tending to

buoy them.

Free-point instrument

Electric wireline service companies run instruments on conductor

lines and are able to accurately determine the stuck point of a pipe.

The instruments are highly sensitive electronic devices, whichmeasure both stretch and torque movement in a string of pipe.

This information is transmitted through the electric conductor

cable to a surface panel in the control unit where the operator

interprets the data.

The basic free-point instrument consists of a mandrel, which

encompasses a strain gauge or microcell. At the top and bottom of

the instrument are friction springs, friction blocks or magnets,

which hold the tool rigidly in the pipe. When an upward pull or

torque is applied at the surface, the pipe above the stuck point

stretches or twists. The change in the current passing through the

instrument is measured by the microcell and transmitted to the

surface for interpretation. When the instrument is run in stuck

pipe, there is no movement in the pipe, therefore there is no pull

or torque transmitted to the instrument. In turn, the gauge at the

surface shows no change in its reading.

Free-point indicators are frequently run with collar locators and

in combination with string shots, chemical cutters and jet cutters.

This combination run saves expensive rig time, and it will also

maintain a continuous sequence in measuring, so that there is less

chance of a misrun in cutting or backing off.

STUCK P IPE LOGS

A log which measures the severity and the length of stuck pipe is

very helpful in determining what method to use to free the pipe.

Pipe recovery logs can express the sticking condition as a percentage.

A vibration is used and measured by a receiver. At stuck intervals,

the sonic vibrations decrease in proportion to the severity of the

sticking. The instrument is calibrated in known free pipe. The pipe

recovery log gives a complete record of all stuck intervals and pos-

sible trouble areas in a string of stuck pipe. This information is very

helpful in evaluating conditions to determine whether to jar on the

stuck section, to wash over the fish, or to sidetrack. It may be used

in drill pipe, tubing, casing or washpipe.

PROBLEM:

DIFFERENTIAL PRESSURE STICKING

Previous Casing Size 9-5/8″

Previous Casing Depth 6,900′ TVD

Pore Pressure @ 13-3/8″ CSG 9.5 PPGOpen Hole Size 8-3/4″

Open Hole Depth, TD 8,200′ TVD

Mud Weight @ TD 20.00 PPG

Casing To Run @ TD 7″ , 32#, N-80

Casing Joint Strength 823,000#

Casing Body Strength 745,000#

Mud Type Water-Base

Friction Coefficient (Assumed) 0.35

1. No centralizers used on 7″ casing:

A) 20 ft pipe embedded for 2″ in the filter cake:

Area = (20 × 12) (2″ ) = 480 sq in

B) 40 ft pipe embedded for 2″ in the filter cake:

Area = (40 × 12) (2″ ) = 960 sq in

Sticking force calculations:

Fs = (Diff. Pressure) × (Contact Area) (Friction Coefficient)

Differential pressure at 6,900 ft:

Diff. Press = (20 − 9.5) (480) (6900) (0.052) = 3,767 PSI

Fs1 = (3767) (480) (0.35) = 632,856 lbs

Fs2 = (3767) (960) (0.35) = 1,265,712 lbs

Drag (estimated) = 50,000 lbs

String wt. in mud = (65.45 − 20) × (32) × (8200)

65.45

String wt. in mud = 182,217 lbs


13/14

Total pulling force required to free the casing:

Ft1 = 632,856 + 50,000 + 182,217 = 865,073 lbs

Ft2 = 1,265,712 + 50,000 + 182,217 = 1,497,929 lbs*

* This pulling force of 1,497,929 lbs exceeds the joint strength

and the body strength of the 7″ , 32 lb/ft, N-80,

buttress casing. Therefore, if we attempt to pull the casing

free, it will be parted.

2. Two centralizers used per joint of the 7″ casing:

On a 40-ft joint, the contact area between the bows and the for-

mation will be as follows:

Contact area with centralizers:

A = (4 bows) (1.5″ ) (24″ ) = 144 sq in

Sticking force, FS:

Fs = (3767) (144) (0.35) = 189,857 lbs

Total pulling force using centralizers:

Ft3 = 189,857 + 50,000 + 182,217 = 422,074 lbs**

** This pulling force of 422,074 lbs is less than the joint

strength and the body strength of the 7”, 32 lb/ft, N-80,

buttress casing. Therefore, the casing can be pulled free

with a safety factor of:

SF = 745,000/422074 = 1.76

Difference in pulling forces with and without centralizers:

F = Ft2 − Ft3

F = 1,497,929 − 422,074 = 1,075,855 lbs

The purpose of the above example is to show how critical the

contact area between the casing surface and the wellbore wall is.

Even with a small contact area, the sticking force is tremendouswhen very high differential pressures exist. In order to minimize or

completely eliminate this contact, the use of a proper centralization

becomes crucial.

If we can imagine running a casing string without centralizers

in an open hole like a long train of cabins without wheels dragged

over the railroad track, the force required to push such train

is much greater than the force required to drag the same train

with wheels.

CONCLUSION

By understanding the causes of pipe sticking and implementing

good drilling practices such as:

1. Good mud and filter cake properties,

2. Pipe and drill string movement,

3. Wiper trips every ±500 ft,

4. Taper type and spiral bottom hole assembly,

5. Controlling penetration rate,

6. Minimizing contact area, and

7. Using casing centralizers,

sticking problems can be reduced or completely eliminated,

resulting in enormous savings.

NOMENCLATURE

A Cross-sectional area, sq.in.

Ac Area of contact between pipe and filter cake.

Cm3 Cubic centimeter.

Cf Coefficient of friction between pipe and filter cake.D Stuck pipe depth, ft.

Dh Hole diameter, inches.

Drag Upward drag in the well, lbs.

∆P Differential pressure = Hydrostatic pressure of mud

minus pore pressure of formation.

E Elasticity factor for steel, E = 30,000,000

ECD Equivalent circulating density, lb/gal.

f Desired native solids fraction in the annulus, decimal

fraction.

F Force, lbs.

Fs Sticking force or total pulling force required to free

stuck pipe, lbs

F1 Pulling force at which S1 was obtained, lbs.

F2 Pulling force at which S2 was obtained, lbs.

∆F = F2 − F1 = differential pulling force, lbs.

ft Foot

Ft Total pulling force to free, lbs.

g grams

L Length of pipe, ft.

lbs Pounds

lb/gal Pounds per gallon, or ppg.

m A number that defines the filtration characteristics of

the mud cake. It increases from zero during stage 1 tosome constant value in stage 3.

MW Mud weight, lb/gal.

n Constant depending essentially on the permeability of

the media (filter paper or porous formation).

PSI Pounds per square inch

Q Pump output, gallons per minute.

ROP Rate of Penetration, ft/hr

S Stretch, inch.

∆S = S2 − S1 = differential stretch due to ∆F, ft



14/14

S1 Stretch due to pulling force F1, inch

S2 Stretch due to pulling force F2, inch

t Time, minutes.

T Temperature change, F

T1 Initial temperature, F

T2 Final temperature, F

∆T = F2 − F1 = Temperature change, F

V Cumulative filtration volume.

W Pipe weight, lb/ft

Wtb Buoyant weight of the pipe, lbs.

SI metric conversion factors

barrel × 1.589 873 E−01 = cu m.

°F (°F-32)/1.8 = °C

ft × 3.048* E−01 = m

ft/hr × 8.466 667 E−05 = m/s

gal × 3.785 412 E−03 = cu m.

in.×

2.54* E+

00 =

cmmile × 1.609 344 E+03 = m

psi × 6.894 757 E+00 = kPa

ACKNOWLEDGMENT

The author gratefully acknowledges the contribution of all those

individuals who helped make this paper possible.

REFERENCES

Bradley, W.B. 1979. Failure of inclined boreholes. Transactions of

the ASME, 232/Vol.101, December.Cheatham, Jr., J.B. 1984. Wellbore stability. JPT , June.

Gatlin, C. 1960. Drilling and well completion. Petroleum Engineering.

Hanna, I.S. and K. Hollister. 1989. PDC bits proved effective in

drilling severely depleted sands in the Gulf of Mexico. SPE19567, San Antonio, Texas, October 8-11.

IADC Rotary Drilling. 1980. Blowout prevention. Third Edition,Unit III, Lesson 3.

Kemp, Gore. 1986. Oilwell Fishing Operations: Tools and Techniques.

McClure, L.J. 1983. Drill Abnormal Pressure Safe ly.

McKeown, G.K., and J.S. Williamson. 1986. An engineeringapproach to stabilization selection. IADC/SPE 14766, present-

ed at the 1986 IADC/SPE Drilling Conference, Dallas, Texas,Feb. 10-12.

Mobil. 1989. Mobil Drilling Technology Handbook. January 13.

Moore, P.L. 1986. Drilling Practices Manual. Second Edition.

Stewart, M.I. A method of selecting casing setting depths to prevent differential-pressure pipe sticking in the Gulf of Mexico.

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