fishing - weather ford pipe rec

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•e a t h e r l o r d ®

Pipe Recovery Handbook



Contents

List of Tables................................................................................................................................... 4Introduction 5

Wireline Pipe Recovery Overview 6

Well Configuration and Conditions 7

Types of Sticking................................................................................................................................... 8

Sand Sticking 10

Mud Sticking 11

Mechanical Sticking 12

Differential Sticking.......................................................................................................................... 13

Key-Seat Sticking...................................................................................................................... 14

Undergauge Holes........................................................................................................................... 15

Sloughing Holes 16

Blowout Sticking 17

Cement Sticking.............................................................................................................................. 18

Lost Circulation 19

Free-Point Services............................................................................................................................... 20

Logging Services 24

Backing Off............................................................................................................................................ 26

Cutting the Pipe..................................................................................................................................... 32

Chemical Cutter 33

Jet Cutter......................................................................................................................................... 34

Radial Cutting Torch........................................................................................................................ 35

Split Shot 36

Severing Tool................................................................................................................................... 37

Mechanical Cutter 38

Pipe Recovery Handbook, 1" ed. July 2005.

The products in this catalog may be covered by one or more United States and/or international patents. Please address all inquir ies

concerning intel lectual property to:

Weatherford International Ltd.

Legal Department

515 Post Oak Blvd., Suite 600

Houston, Texas 77027 USA

Tel: +1-713-693-4000

3 © 2005 Weatherford . All r ights reserved.



L ist of T ab les

Table 1-Weatherford's Process for Estimating Free Point 22Table 2-Buoyancy Factors 23

Table 3-0verpull Weights 23

Table 4- Tightening Torque 26

Table 5-Reverse Torque 26

Table 6-String-Shot Strength for Tubing 28

Table 7-String-Shot Strength for Drillpipe 29

Table 8-String-Shot Strength for Drill Collars 30

Table 9-String-Shot Strength for Casing and Washpipe 31

© 2005 Weather iord . All r ights reserved. 4



Introduction

No two sticking situations are alike. Myriad wellconfigurations, well conditions and types of sticking

mean that each pipe recovery operation is unique. All

sticking situations, however, have two factors in

common: stuck pipe is always an unanticipated

problem; and freeing stuck pipe is always an urgent

requirement.

Successful pipe recovery operations depend onexperienced crews. Experienced crews blend

knowledge and technology to analyze specific well

configurations and conditions, identify the cause of

sticking, determine the free point, recover the pipe, and

leave the fishing crew with a retrievable fish.

Technology advances bring new techniques while enhancing the old to speed the recovery of production.




Wireline Pipe Recovery Overview

Though each job is unique, a good operatorunderstands the value of using a standard process to

approach each situation.

The following flowchart illustrates Weatherford'srecommended process for pipe recovery.

Analyze the well configuration and well conditions at the time of sticking.

II

Gather and analyze information about current well conditions.

Gamma ray, pipe recovery, and noise/temperature logs might provide

additional relevant information.

II

Work the pipe and determine the estimated free point.

II

Run a free-point tool to determine the uppermost stuck point.

A pipe recovery log can be used to identify the amount of stuck pipe

below the uppermost stuck point.

II

Select the best method and tools to separate the pipe.

II

Remove the free portion of the pipe from the well.




W ell C onfigu ration and C ond itions

Well ConfigurationWell configuration and well conditions affect both why

the pipe is stuck and how it will be freed. The easiest

way to visualize the many elements of the well is to

make an annotated sketch of the well at the start of the

job, before beginning pipe recovery operations. A good

well sketch facilitates communication between the

customer, fishing personnel, and the Weatherford pipe

recovery specialist. It should include

• total depth of well and hole size;

• all casing sizes and weights;

• string configuration including pipe sizes, depth,

weight, and when necessary bottom hole assembly;

• hole angle and any kickoff points;• composition and weight of the wellbore fluid;

• bottom hole temperature (BHT);

• surface pressure;

• bottom hole pressure (BHP);

• cause of sticking, when known;

• record of previous pipe recovery attempts.

Well Conditions

Pipe recovery operations may be complicated by

certain challenging well conditions, including

• shallow straight holes;

• deep straight holes;

• directional (deviated) holes;

• high temperatures;

• high pressures;

• multiple tubing strings;

• mixed strings.




T yp es of S ticking

Sand

Differential

© 2005 Weather iord . All r ights reserved.

--

I I I I

Mechanical

8

Mud

Key-Seat




--~-_---- --_

----'- ~, ---_I

---~_r- --:- -_ _ -_ --=-----= -,- - --

-

Undergauge Holes

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.. , . ,.... '

'_ _

",' '~.~:.',I'

: ~ ~ ~ t M : : : . ~ t (Cement

' ...~'-_.... .L._"

•

IL -

Blowout

9

1

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Sloughing Holes

Lost Circulation

© 2005 Weatherford . All r ights reserved.




Sand StickingClassic sand sticking occurs with tubing in a cased

hole. A leaking packer or a hole in the tubing or casing

can allow sand to enter the annulus. Over time, sand

can accumulate to a level that prevents the string from

being pulled.

Identification

• Is there a history of sand production at the surface?

Free-Point TendenciesFree-point operations in sand-stuck pipe can be

challenging. As the pipe is worked, small pockets, or

voids, may develop at the tubing collars. These voids

allow just enough movement for the free-point tool to

indicate free pipe at points below the level where the

pipe can possibly be retrieved after a backoff or cut.

Using higher working weights when determining the

free point helps to obtain an accurate backoff or cutting

depth.

Stretch readings in sand-stuck pipe are often erratic.

Torque readings can generally be taken at deeper

depths than stretch readings, and are usually

repeatable. Take both stretch and torque readings sothat there is a point of comparison when determining

the free point.

Hole

Techniques for Freeing the Pipe

When picking a backoff or cut depth in sand-stuck

pipe, choose a point at some distance uphole from the

stuck point, where the pipe is 100 percent free. After

the pipe is backed off, the remaining fish should be

washed over to remove all remaining sand from the

annulus. Pipe recovery operations can then continue.Hole in Tubing Allowing Sand to Enter

Annulus

© 2005 Weatherford. A l l r ig h ts reserved. 10




Mud StickingMud sticking is typically encountered in cased holes, but it

can also occur in openhole environments.

Mud sticking commonly occurs when trying to retrieve

tubing on a recompletion job. Wells are often completed

with mud behind the tubing above the packer. Over time,

weighting materials in the dril ling mud (particularly barite)

may settle and collect on top of the packer. The weighting

materials can harden and stick the pipe. High

temperatures can accelerate the process.

In open holes, contaminants such as shale, soluble salts

and acidic gases can mix with the mud, dehydrating it and

causing the pipe to stick. Contaminants can have thesame effect in cased holes when there is a hole or leak in

the casing or tubing.

Identification

• What type of fluid is in the annulus?

• How long has the fluid been in the hole?

• When was the last time the mud was circulated?

Mud Sticking in Cased Hole

Free-Point Tendencies

The pipe should be worked thoroughly to free as much

pipe as possible before running the free-point indicator.Working down below the weight of the string usually frees

the pipe more effectively than pulling strictly above the

weight of the string.

Continuous working of the pipe may create small pockets

or voids around the tubing collars or tool joints. The voids


indicate free pipe at points below the level where the pipe

can possibly be retrieved after a backoff or cut.

Using higher working weights when determining the free

point helps to obtain an accurate backoff or cutting depth.

Techniques for Freeing the PipePerforations can be used in open holes to break up the

mud and encourage circulation. In cased holes where the

fluid in the annulus is in a liquid or semi-liquid state to the

packer, perforating the tubing above the packer may

establish circulation and allow the assembly to be pulled

from the hole.





Mechanical StickingMechanical sticking typically occurs

in cased holes, but it may also

occur in openhole environments.

Types of mechanical sticking

include:

• collapsed casing

• bent pipe• stuck packers

• junk in the hole

• wrap-around tubing

Stuck PackersWhen the release mechanism on a

retrievable packer fails, the packer

is stuck, preventing the tubing from

being pulled. With permanent

packers, corrosion can form

between the tubing and the packer,

preventing the tubing from being

pulled.


Collapsed CasingCasing may collapse because of

well pressures or for other reasons,

causing the tubing to stick.

I

=

II

; , . .

JunkSticking may occur when a foreign

object (for example, a wrench,

tong, or hammer) falls into the hole

or a piece of the tool string breaks

off in the hole. The junk can wedge

next to the pipe string and cause

the pipe to stick.

12

Bent PipeSticking may also occur when the

pipe is bent. Bent pipe is usually a

result of dropping the pipe.

Wrap-Around TubingWrap-around sticking can occur

when multiple strings of tubing are

run separately instead of in dual

mode, causing the tubing strings to

twist and wrap around each other

as they are run in the hole.




Differential Sticking, Also

Known as "Well Sticking"

Differential Sticking

Differential sticking, also called wall sticking, is a

common cause of stuck pipe in open holes. Differential

sticking occurs when the hydrostatic pressure exerted

by the mud column in the wellbore is greater than the

formation pressure. The pressure differential (in other

words, suction) causes the drill string to stick to the

well bore. The pressure differential can also create fluid

loss to a porous and permeable formation. Over time, a

mud-cake buildup can reinforce the sticking.

Challenges

Freeing differentially stuck pipe can be diff icult because

of the strength of the hydraulic force holding the string

to the side of the wellbore. The hydraulic force may be

a million pounds or more. Under such conditions, a

washover might not free the pipe, a string shot might

not result in a backoff, and jarring operations might be

unsuccessful. Sticking can intensify with time;

therefore, it is essential to act immediately to free

differentially stuck pipe.

Identification• Is the hydrostatic pressure of the mud column in the

wellbore greater than the formation pressure

opposite the stuck pipe interval?

• Is the formation opposite the stuck point porous and

permeable, possibly sandstone?

• Was the pipe stationary for several minutes opposite

a porous and permeable zone (for example, while

making a connection), allowing a fairly large area of

the pipe to come into contact with the formation?

• Is it impossible to pull or rotate the pipe? Can the

well fluid be circulated at normal pressures and

rates?

• Is the hole clean and in good condition?• Is the wellbore fluid clean and in good condition?


Free-point readings can help to identify differential

sticking. When sticking is confined to a single interval,

free-point readings will drop off over a very short

distance. If there are several stuck intervals

contributing to the overall sticking, free-point readings

will drop off over a longer distance. A gamma ray log

can determine whether the formation has numerous

porous and permeable zones.

Mud logs and temperature logs can also provide

information that may help to pinpoint the cause of

sticking and identify the best means of pipe recovery.


Rotating or applying downward movement to the pipe

is more likely to break the mud seal than pulling on the

pipe.

Lowering the mud weight may also free a differentially

stuck string. However, the mud weight should not be

reduced if well control is a problem. Jarring operations

can also be conducted to try to free the pipe.

If the pipe needs to be backed off or cut, free-pointreadings must be taken to establish the point at which

the pipe is completely free. When dealing with

differentially stuck pipe, it is essential to leave sufficient

pipe exposed, both to act as a guide for fishing tools

and to ensure a good reconnection. A backoff or cut

close to a casing shoe or in a washed-out area or

dogleg may leave a fish top that cannot be re-engaged.





Key-Seat StickingKey seats are formed during drilling operations, when

weight is applied to the bit through the drill collars and

the drillpipe is normally in tension. If the hole is

deviated (in other words, if there is a dogleg),

continuous rotation can slowly cut a groove into the

high side of the dogleg, forming a key seat.

The groove (key seat) is smaller than the main

borehole because it is not drilled by the bit, but worn

into the formation by the smaller-diameter body of the

drillpipe. When the pipe is pulled from the hole, the

larger-OD stabilizers, drill collars and tool joints will not

pass through the key seat.

Identification

• Did the driller encounter excessive drag at measured

tool joint intervals while pulling out of the hole?

• Is the pipe free to rotate and circulate?

• Is it possible to work the pipe up and down, but not

possible to move it up past a certain point?

• Was the pipe moving upwards when it became

stuck?


A free-point survey can help to identify key-seat

sticking. To obtain stretch readings, the pipe must be

pulled into the key seat and worked above the normal

weight. If the pipe rotates freely, torque cannot be

worked down to the stuck interval to obtain torque

readings.

If the pipe has been pulled into the key seat tightly

enough to become completely stuck, the free-point

readings will drop off over a short interval. A key seat

may be indicated if the pipe goes from completely free

to completely stuck near an 00 change in the string.


The backoff point should be located several joints

above the key seat so that the top of the fish is in the

main borehole and out of the key seat. Fishing tools

can then be made up on the fish in the normal part of

the hole. Coordination with the fishing tool supervisor is

critical when dealing with key seats.


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Key Seat in Deviated Hole




Undergauge HolesSticking can occur in open holes where the diameter of

the hole is smaller than the diameter of the pipe.

Undergauge holes are caused by formation expansion

or by abrasion on the bit and stabilizers.

Using mud that has a lower hydrostatic pressure than

the formation when drilling through shale with a high,

expandable clay content can cause the shale to deform

and the hole to close.

Drilling through a salt section using oil-based mud can

create an undergauge hole because the weight of the

overburden may cause the salt to flow into the

borehole, shrinking the diameter.

Drilling through an abrasive hole section can dull the

bit and reduce the gauge (00) of the bit and

stabilizers. On subsequent trips with a new bottom hole

assembly, the bit and stabilizers can become stuck.

L- _- -= - - = = . - -~-- ~-

Identification

• What was the diameter of the old bit and stabilizers?

• Did the sticking occur when running a new, full-size

bottomhole assembly in the hole?

• Were the drill string and new bottom hole assembly

rotated while tripping in the hole?

Formation Expansion


Stretch readings typically drop off over a short interval,

usually near the bit. Torque readings also drop off

suddenly.


If a full-gauge bit has become stuck while tripping in,

jarring with an upward force will usually free the pipe. If

the bottom hole assembly is stuck below the

undergauge hole, a backoff operation will be

necessary. After a backoff, it may be possible to jar thefish out of the hole. If jarring is unsuccessful, a

washover operation will enable the fish to be retrieved.

Bit and Stabilizer Abrasion





Sloughing HolesSloughing occurs when the wall of the well bore is

unstable. This unstable condition can cause the wall of

the wellbore to collapse, or slough, into the drilled hole,

trapping the drilling assembly in place.

If improper hole conditions are present, any type of

formation can slough into the wellbore and stick the

drilling assembly. A sloughing formation may occur

when a shale sequence absorbs water from the drilling

fluid. The water causes the shale to expand and fall

into the hole, sticking the drill ing assembly.

Sloughing is also caused by

• overpressured shale sections;

• steeply dipping shale beds;

• turbulent flow in the annulus;

• ledges that break off;

• surge pressures;

• accumulated particles in cavities.

Identification

• Before sticking occurred, were excessive amounts of

shale on the shakers at bottoms up?

• Did the driller encounter hole drag?

• Was there any filion the most recent bit trip?

• Is circulation either greatly reduced or impossible?• Were there variations in pump pressure before

sticking occurred?

• Is it possible to rotate and pump fluid into the

formation with no returns?


The pipe should be worked to free it as far as possible

before running the free-point survey. Continuous

working of the pipe may create small pockets, or voids,

in the debris around the collars or tool joints. The voids


indicate free pipe at points below the level where the

pipe can possible be retrieved after a backoff.


Sloughing Resulting from Unstable

Wellbore Wall


A backoff operation is typically performed when

sticking results from a sloughing hole. It is important to

establish a backoff point where the pipe is completely

free. If the pipe is backed off at a depth at which it

cannot be pulled, attempts to pull the pipe will lodge

the tool joints and collars above the pockets, making it

difficult, if not impossible, to engage the fish.

16




I

Blowouts can result in more than one

struck point.

Blowout Sticking

Blowout sticking occurs in open holes, and ischaracterized by sand, shale, and other formation

debris blowing uphole, bridging over, and sticking the

pipe. The debris can also blow into another formation

(an underground blowout). Pressurized fluid movement

can be to the surface or to a low-pressure formation

downhole. In these situations, there is often more than

one stuck interval.

Blowouts typically occur when the formation pressure

exceeds the hydrostatic pressure of the drilling fluid.

The following conditions increase the likelihood of ablowout or pressure kick:

• insufficient mud weight resulting from

- efforts to free the pipe or avert differential sticking

by lowering the mud weight

- a lack of geological data about the field

- formation liquids and/or gases entering the mud

system and lowering the mud weight

• failure to keep the hole full of fluid as a result of

improper fluid measurement when tripping the pipe

• pulling the pipe from the well too quickly when the

hydrostatic pressure of the drilling mud is almost

balanced with the formation pressure, causing a

swabbing, or piston, effect

Identification

• Where is the casing set?

• Has there been an unexpected increase in the mud-

tank volume?

• Has there been a kick, or are there ongoing efforts to

control a kick?


The free-point tool typically registers clear movement

in the free portions of the pipe and indicates a change

from completely free to completely stuck over a few

feet.

Torque readings may show some movement in the

stuck portion of the pipe; however, movement in the

stuck area will rapidly decrease with depth.


When sticking occurs because of a blowout, there is

typically more than one stuck interval. Free-point

surveys alone are generally inadequate for determining

the safest and most economical pipe recovery

procedure because the free-point tool only defines the

uppermost stuck section. Logging surveys used in

conjunction with the free-point survey can provide

useful information for planning subsequent fishing

operations. A pipe recovery log can provide information

about the sticking conditions below the uppermost

stuck point. Noise/temperature logs can be used to

identify the source of the blowout and to verify whether

fluid movement is still occurring.





Cement Sticking

Identification

• Has cement been pumped into the well?

• Did the cement job go as planned?

I

Cement sticking can occur in both open and cased

holes and is usually a result of one of the following:

• a mechanical malfunction (for example, a pump truck

malfunction or a leak in the pipe string)

• miscalculation of displacement amount resulting from

human error or hole washout

• efforts to contain a downhole blowout or prevent

excessive lost circulation

• human error


Stretch and torque readings will drop off over a short

interval unless the cement has not had time to set

completely.


A backoff or cut can be used to recover the

uncemented portion of the pipe. Jarring operations will

be successful only if the cemented section is very

short. If the pipe is centered in the hole, a washover

can be used to free the fish. If the pipe is not centered,

it may be necessary to mill up the pipe and cement.

When a very long interval of pipe is cemented,

sidetracking or abandoning this portion of the well may

be the most economical solution.

'."..

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Cement-stuck points occur in open

and cased holes.





Lost CirculationLost circulation most commonly occurs when the

hydrostatic pressure exerted by the drilling fluid cracks

or fractures shallow, unconsolidated formations,

allowing the drilling fluid to flow freely into the

formation.

The movement of the drilling fluid into the formation

can cause washouts, which can lead to sloughing hole

sticking.

If the wellbore fluid has been weighted up to drill

through a high-pressure zone and lost circulation

occurs, shallow gas can cause a blowout.

Efforts to prevent lost circulation may cause cement

sticking.

Identification

• Has there been a decrease in returns at the pit?


Free-point tendencies are similar to those for sloughing

holes, blowout sticking, and cement sticking,

depending on the type of sticking that occurs as a

result of lost circulation.


Recovery operations are dictated by the type of

sticking that occurs as a result of lost circulation.

Lost circulation leads to a variety of

sticking types.




Free-Point Services

OverviewThe free point is the deepest point at which the pipe

can be recovered by a given method.

Most free-point tools are strain gauges. In other words,

they measure the stretch or torque of the pipe between

a top anchor and a bottom anchor. Stuck pipe will not

move in response to applied stretch or torque.

Because a free-point tool measures stretch or torque,

and because stuck pipe will not move in response to

surface-applied stress, a free-point tool can determine

whether the pipe is stuck or free at a given point.

Estimating the Free Point

Before beginning a free-point survey, it is important to

take a manual stretch reading to determine an

estimated free point. Estimating the free point indicates

which portion of the pipe string is stuck (for example,

the collars, drillpipe) and helps to determine where to

calibrate the free-point tool, which will save time during

the free-point survey. An estimated free point also

provides a point of comparison for the results of the

free-point survey.

The free point is estimated by applying overpull to the

pipe and measuring how much the pipe stretches in

response. To estimate the free point, first find the total

string weight. Pipe in a well filled with fluid will weighless than the pipe's calculated weight in air because of

the buoyancy effect of the well fluid. If the well contains

fluid, the weight of the pipe string must be adjusted for

buoyancy. To find the appropriate buoyancy factor,

refer to Table 2-Buoyancy Factors. The appropriate

buoyancy factor can also be calculated using the

formula below:

Buoyancy Factor = 1 (Mud Weight in Ib/gal + 65.63)

If the rig's weight indicator is zeroed with the block, the

total string weight should also include the weight of the

block.

Given the total string weight, find the amount ofoverpull needed to stretch the pipe 3-1/2 in.l1 ,000 ft. To

find the overpull, refer to Table 3-0verpull Weights, or

use the following formula:

Overpull = 2208.5 x Pipe Weight/ft


Free-Point SurveysA free-point survey can identify the uppermost stuck

point in a pipe string and assess the severity of the

sticking. The survey helps to determine whether to

back off or make a cut, and it provides essential

information for selecting the correct tools to use during

the pipe recovery operation. The survey cannot provide

information about conditions below the uppermost

stuck point. A pipe recovery log can give an indication

of sticking conditions below the stuck point to allow

better planning of future operations.

To obtain an accurate free-point survey, it is important

to calibrate the free-point tool's sensor(s) to the free-

point panel before beginning the survey. Calibrating thetool in free pipe provides a baseline reading-a known

amount of stretch or torque in free pipe when stress is

applied to take a free-point reading. The baseline

reading serves as a point of comparison for readings

taken during the free-point survey.

Accurate free-point readings also depend on the free-

point tool remaining stationary during the survey with

respect to the pipe. Using a slack joint in the free-point

tool string helps to keep the tool stationary. A slack joint

can take sinker bar weight and wireline weight off the

free-point tool so that the tool is free to respond to pipe

stretch or torque.

Free-Point Stretch Surveys

A free-point stretch survey is typically conducted when

the free pipe is to be cut and recovered. The survey

should be started well above the estimated free point,

typically at the calibration depth. Free-point readings

should be taken at 200-ft intervals until stuck-pipe

conditions are indicated. When stuck pipe is indicated,

closely survey the interval between the stuck pipe

reading and the last free pipe reading to define the

uppermost stuck point.

Free-Point Torque Surveys

A free-point torque survey is typically conducted when

the free pipe is to be backed off and recovered. In

addition to indicating the uppermost stuck point, a free-

point torque survey also provides information about the

amount of torque trapped by the hole; whether torque

can be transmitted to the depth of interest; and how

many rounds it will take to transmit torque to the point

of backoff.

20



Free-Point Services

Before beginning a free-point torque survey, it isimportant to tighten the free pipe fully. When torque is

added to the pipe to take a free-point reading, all the

applied torque should be released before continuing

the survey. It is not possible to recover all the applied

torque if the pipe is loose, or if torque is being lost

downhole. It is important to work with a pipe recovery

crew that is able to prevent trapped torque, work

torque downhole, take free-point readings using both

right- and left-hand torque, and distinguish between

torque dropoff caused by sticking and torque dropoff

caused by wall drag.

Types of Free-Point ToolsA free-point tool is run with a collar locator on single-

conductor electric wireline. Most free-point tools can be

run in combination with a string shot.

A free-point tool uses at least one detector to sense

stretch and torque. The tool is anchored in the survey

pipe both above and below the detector(s). Tools can

be anchored with bowsprings, magnets, or motorized

anchors.

Weatherford's dual-sensor free-point tool (DSFT) uses

separate sensors to measure stretch and torque, and

can directly measure left- and right-hand torque equally

well. This tool was specifically designed to address

deep, hot, high-pressure wells. It can operate

continuously at 400°F (204.4 DC)and at 425°F

(218.3°C) for up to two hours.




Free-Point Services

Table 1-Weatherford's Process for Estimating Free Point

Step Action Example

1 Determine the total string weight, For 13,500 ft (4,114,8 m) of 2 3/8-in.,

adjusted for buoyancy. Add the 8-round tubing weighing 4.7 Iblft,

weight of the block, when applicable. calculate the weight of the string

in air by multiplying the pipe length

by the pipe weight:

13,500 ft x 4.7 Ib/ft = 63,450 Ib

Adjust the string weight for the

buoyancy effect of the 10-lb/galmud by multiplying the string

weight by the buoyancy factor of

the mud (0.847):

63,450 Ib x 0.847 = 53,742 Ib

If the rig's weight indicator is zeroed

with the block, add the weight of the

block to find the total str ing weight:

53,742 Ib + 11,000 Ib = 64,742 Ib

Pick up the total string weight

2 (adjusted for buoyancy and the block,

when applicable).

3 Mark the pipe at the top of the rotary.

Apply the overpull necessary toIn this example, the overpull needed to

4 stretch the pipe 3.5 in.l1 ,000 ft

1(88.9mm/304.8 m).stretch the pipe is 10,000 Ib (4,535.9 kg).

5 Mark the pipe at the top of the rotary.

Measure the distance between the twoFor the purposes of this example, assume

6marks.

that the distance between the two marks

is 29 in. (736.6 mm).

29 in . -i- 3.5 = 8.286

Divide the distance by 3.5, then multiply 8.286 x 1,000 = 8,286

7 the answer by 1,000 to find the estimated

depth to the free point. In this example, the estimated free point is

at 8,286 ft (2,525.6 m).




Free-Point Services

Table 2-Buoyancy Factors

Fluid

Weight Buoyancy

(Ib/gal) Factor

8.4 0.872

8.6 0.869

8.8 0.866

9.0 0.862

9.2 0.859

9.4 0.856

9.6 0.853

9.8 0.85010.0 0.847

10.2 0.844

10.4 0.841

10.6 0.838

10.8 0.835

11.0 0.832

11.2 0.829

11.4 0.826

11.6 0.823

11.8 0.820

12.0 0.817

12.2 0.814

12.4 0.811

12.6 0.807

12.8 0.804

13.0 0.801

13.2 0.798

13.4 0.795

13.6 0.792

13.8 0.789

14.0 0.786

14.5 0.778

15.0 0.771

15.5 0.763

16.0 0.75616.5 0.748

17.0 0.740

17.5 0.733

18.0 0.725

18.5 0.717

19.0 0.710

19.5 0.702

20.0 0.695

Table 3-0verpull Weights

Pipe 3 1 /2 -in .

Pipe 00 Weight Stretch

(in.) (IbItt) Tensions

Tubing

11.80 4,000

2.25 5,000

1-1/4 2.40 5,500

1-1/2 2.90 6,500

2-1/16 3.40 7,500

4.70 10,0002-3/8 5.30 12,000

5.95 13,000

6.50 14,000

2-7/8 7.90 17,000

8.70 19,000

9.30 20,000

3-1/2 10.30 23,000

12.95 28,000

411.00 24,000

13.40 29,000

12.75 28,000

4-1/2 15.50 34,000

19.20 42,000

Orillpipe

2-3/8 6.65 15,000

2-7/8 10.40 23,000

3-1/2 13.30 30,000

4-1/2 16.60 36,000

5 19.50 43,000

Casing

5 15.00 33,000

5-1/2 17.00 38,000

6-5/8 24.00 53,000

7 35.00 77,000

7-5/8 29.70 66,000

8-5/8 40.00 88,000

9-5/8 43.50 96,000

10-3/4 45.50 100,000

23 © 2005 Weatherford. A l l r ig h ts reserved.



L og g in g S e rv ic es

Pipe Recovery LogsIn conjunction with a free-point survey, a pipe-recovery

log can provide a complete record of all stuck intervals

and possible trouble areas in a string of stuck pipe.

The log indicates the following:

• uppermost stuck point

• length of each stuck interval below the uppermost

stuck point

• severity of sticking at each interval below the

uppermost stuck point

• how much each interval contributes to the total stuck

condition of the pipe

• safest, most practical, and most economical pipe

recovery method

Weatherford's pipe recovery logging system consists of

a transmitter and a receiver. The transmitter emits

rapid sonic pulses that create a continuous vibration

through the pipe to the receiver. As the sonic pulse

travels, it decreases at stuck intervals in proportion to

the severity of the sticking condition. The receiver

measures the amplitude of the resultant sonic wave.

The logging tool is run on a single-conductor electric

wireline. The tool is calibrated in known free pipe,

usually near the bottom of the surface pipe or the last

casing string. After the log is recorded, a signal

attenuation scale is placed on the log. This scale

shows the severity of sticking at each interval.

Sonic pipe recovery systems cannot be used in gas

environments or gas-cut mud. Readings in these

conditions are erratic and unreliable.


'" ,

=t

!oo·

>--~~~ool~~_~

" J

~ ~e < 1I n Tu ; > ~

u ,~.,

"

-'l~±-+- I~ 'OO

+- - - - + - - c '

I-

~ 1=

1 =->

~1~~1l

---r- t" I .=.

~,L.

-.:!:_

--'= 1 = - - 1 e = ± = t

e2- - r -

A T\I I,ii..lJU tN tW~

~ ~. • • ~ _~ ,,!~ "I 11!, ,_n! 0 _

;.

-,

Examples of Weatherford Pipe Recovery Logs. The log

on top indicates free pipe, and the log on the bottom

indicates stuck pipe.

24



L o g gin g S e rv ic es

Gamma Ray LogsWhile the pipe recovery log may be run independently,

Weatherford recommends running it in conjunction with

a gamma ray log to correlate the stuck pipe to the

formation. A gamma ray log identifies the formation

type, or lithology. Information about the formation type

can help to determine the type of sticking and the most

practical and economical method of recovering the

stuck pipe.

Noise/Temperature Logs

Weatherford's noise/temperature logs may be run in

combination and displayed as a single log.Noise/temperature logs identify

• lost circulation zones;

• underground blowouts in source and thief zones;

• drill string or tubing leaks;

• fluid movement behind the pipe;

• gas versus liquid flow.

If interpreted properly, the information gathered by the

noise/temperature logs may suggest the conditions of

the borehole and the most practical, most economical

pipe recovery method.

Collar Logs

A collar log is always recorded simultaneously with

pipe recovery logs, gamma ray logs, and

noise/temperature logs. Distortions in the magnetic

field set up by the collar locator are used to identify tool

joints, collars, and other points downhole. The

information gathered by the collar log is used for depth

control on subsequent runs.

Collar Locator 2000 Hz-9 1.2 2

1~;Ov~z

2000

1210

Differ~~~i~;)Temp 230

2

6~~V~Z

2000

1 -0.5 (degf) 0.5 2

2~~V~Z

2000

Depth

(It) 200

;:~~; ; l ; X400

i ! H~ : n X450

; ; l ;i ! l ! X500

~ : : :~:i~ X550

; ; n

•! i ! X600~ : n; ; n

X650~:::~ : n~:;l X70018(2

Examples of temperature (left) and noise (right) logs

show gas entry into the pipe.




B ac king O ff

OverviewA successful backoff depends on the following

conditions:

• free pipe at the point of backoff

• sufficient left-hand torque at the point of backoff

• proper weight of the pipe string at the point of backoff

• a string shot of adequate strength for the specific

pipe

Free Pipe

It is important to interpret the results of the free-point

survey correctly to ensure that the pipe is completely

free at the point of backoff. Performing backoffoperations in pipe that is not completely free can result

in a backoff at an unplanned, undesirable depth or a

failure to achieve a backoff. Backing off at a depth

where pipe movement is restricted (in partially stuck

pipe) or too close to a washed-out area or dogleg could

leave a fish top that cannot be re-engaged. When

backing off, it is essential to leave sufficient free pipe

exposed, both to act as a guide for fishing tools, and to

ensure a good reconnection.

Torque Considerations

The pipe must be tightened completely before applyingreverse (left-hand) torque to make a backoff. Table

4- Tightening Torque provides a guideline for the

amount of right-hand torque needed to tighten the pipe.

The actual number of rounds used to tighten the pipe

will vary, depending on hole conditions and the

condition of the pipe. The amount of right-hand torque

applied to tighten the pipe should always be greater

than the amount of left-hand torque that will be used to

make the backoff.

When determining the amount of reverse torque to

apply for the backoff, consider the type, size, depth,

and condition of the string to be backed off. Fatigued

pipe will have lower maximum yield strength than pipe

in good condition. Table 5-Reverse Torque provides

general guidelines for the amount of reverse torque

needed to back off the pipe. The actual number of

rounds used to back off the pipe will vary depending on

hole conditions and the condition of the pipe.


Table4-Tightening Torque

PipeTightening Torque

(Rounds per 1,000 ft)

Drilipipe 1 round

Tubing 1-1/4 to 1-1/2 rounds

Casing 1/8 to 1/ 4 round

Table 5-Reverse Torque

PipeReverse Torque

(Rounds per 1,000 ft)

Drilipipe 1/4 to 3/4 round

Tubing 3/4 to 1-1/4 rounds

Casing 1/ 4 round

String Weight

At the point of backoff, the pipe string should be at theneutral weight. The neutral weight is the weight at

which the threaded connection at the backoff point is

neither in tension nor in compression. To determine the

neutral weight, it is necessary to know the pipe weight

at the backoff point, adjusted for buoyancy and the

weight of the block when applicable.

String Shots

A string shot backoff relies on the impact provided by

the detonation of a string shot to loosen a pipe

connection. The string shot itself does not free pipe or

unscrew a threaded connection; it simply provides

extra energy to the torqued connection, which helps to

unscrew the connection. The effect is similar to that of

striking a threaded connection with a hammer while

applying left-hand torque with wrenches. The rig-

provided torque actually unscrews the pipe; the string

shot determines which pipe connection will be

unscrewed by the torque.

26



B ac king O ff

String shots may also be used to• release stuck packers or fishing tools (for example,

overshots);

• remove corrosion from the pipe;

• clean up perforations;

• jump threaded and coupled pipe connections;

• remove jet nozzles from drill bits to increase the rate

of circulation.

A successful string shot backoff depends on the

building of a reliable, problem-free string shot. String

shots must be strong enough to back off the pipe

without damaging the threaded connection or the body

of the pipe. Shot strength is expressed in grains perfoot of detonating cord placed on the shot rod. The

recommended shot strength depends on

• size of the pipe to be backed off;

• weight of the wellbore fluid;

• depth range of the backoff.

String shot strength charts list recommended starting

strengths, which may need to be adjusted for

operational conditions. Tables 6 through 9 provide

string-shot strengths for tubing, dril lpipe, drill collars,

casing and washpipe. The recommendations listed in

these tables apply only to wellbores with fluid tops

above the backoff depth.

Completing the BackoffThe pipe will typically spin free after the string shot is

detonated if the neutral weight and proper amount of

left-hand torque have been applied. After the string

shot is detonated, pull up on the wireline and position

the collar locator at the next threaded connection

uphole from the backoff attempt. To verify that the

backoff was completed, pick up on the pipe while

observing the rig's weight indicator and the wireline

collar locator. If no additional weight is gained as the

pipe is picked up, the backoff was successful. If weight

is gained as the pipe is picked up, the pipe might not

be unscrewed completely. Lower the pipe back down

to the neutral weight and have the rig operator applyleft-hand torque to complete the backoff.




B ac king O ff

Table 6-String-Shot Strength for Tubing

The following table lists suggested string-shot sizes in grains per ft.

Fluid WeightDepth of Backoff

(tt)Pipe

Size o to 5,000 to 7,500 to 10,000 to 15,000 to 20,000 to

(in.) Ib/gal kglm3

5,000 7,500 10,000 15,000 20,000 25,000

10 1,1983/4, 40 80 80 to 160 160 to 240 240 to 320

1 and 14 1,678 40

1-1/418 2,157 80 80 to 160 160 to 240 240 to 320 320 to 480

10 1,198 80 to 160 160 to 24080 320 to 400

1-1/2 14 1,678 40 80

160 to 240 240 to 320

18 2,157 80 to 160 320 to 480

10 1,198 80 to 160 16 to 24080 320 to 400

2-1/16 14 1,678 80 160 240 to 320160 to 240

18 2,157 160 240 to 400 400 to 480

10 1,198 80 to 160 160 to 240 240 to 32080 80 to 160 80 to 160

2-3/8 14 1,678 160 to 240 240 to 320 320 to 400

18 2,157 80 to 160 160 160 to 240 240 to 320 240 to 400 320 to 480

10 1,198 80 to 160 80 to 160 160-32080 to 160 80 to 160 320 to 480

2-7/8 14 1,678 160 to 240 240-400

160 to 320

18 2,157 160 160 160 to 240 320-480 320 to 560

10 1,198 160 to 240160 160 160 to 240 320 to 400 400 to 480

3-1/2 14 1,678 240 to 320

18 2,157 160 to 240 160 to 240 160 to 320 240 to 400 320 to 480 400 to 560

10 1,198 160 240 to 320 320 to 400 480 to 560

4-1/2 14 1,678 240 240 400 to 480 560 to 640160 to 240 320 to 400

18 2,157 480 to 560 560 to 720

© 2005 Weatherford . All r ights reserved. 28



B ac king O ff

Table 7-String-Shot Strength for Drillpipe

The following table lists suggested string-shot sizes in grains per ft; SO-grain detonating cord is recommended.


(ft)Pipe


(in.) Ib/gal kglm3

5,000 7,500 10,000 15,000 20,000 25,000

10 1,198 240 to 320 320 to 400 480 to 560 560 to 720160 160 to 240

2-3/8 14 1,678 320 to 400 400 to 560 560 to 640 720 to 800

18 2,157 160 to 240 240 to 320 320 to 480 560 to 720 720 to 800 800 to 1,040

10 1,198 160 160 160 to 240 240 to 320 320 to 400 320 to 480

2-7/8 14 1,678 240 240 to 320 320 to 400 400 to 480 400 to 560240 to 320

18 2,157 240 to 320 320 to 400 320 to 480 480 to 560 480 to 640

10 1,198 160 240 400 to 480 480 to 560240 to 320 320 to 400

3-1/2 14 1,678 240 480 to 640 560 to 720240 to 320

18 2,157 240 to 320 320 to 480 400 to 640 560 to 720 640 to 800

10 1,198 160 240 400 to 480 480 to 560240 to 320 320 to 400

4 14 1,678 240 480 to 640 560 to 720

240 to 32018 2,157 240 to 320 320 to 480 400 to 640 560 to 720 640 to 800

10 1,198 240 320 320 to 400 400 to 560 480 to 560 560 to 720

4-1/2 14 1,678 400 400 400 to 640 640 to 720 640 to 800320 to 400

18 2,157 400 to 480 400 to 560 480 to 720 640 to 800 720 to 880

5 DP 10 1,198 320 to 400 320 to 400 480 to 640 560 to 640 640 to 720

and400 to 480

4-1/214 1,678 400 to 480 480 to 720 640 to 800 720 to 880

400 to 480HWDP 18 2,157 400 to 560 480 to 640 560 to 800 720 to 880 800 to 960

10 1,198 400 480 to 560 560 to 640 640 to 880 880 to 1,0405-9/16

DPand 14 1,678 480 to 560 640 to 720 720 to 880 960 to 1,120

5HWDP 400 to 480 560 to 640

18 2,157 640 to 800 880 to 1,160 1,040 to 1,360




B ac king O ff

Table 8-String-Shot Strength for Drill Collars



(tt)Pipe

Size Oto 5,000 to 7,500 to 10,000 to 15,000 to 20,000 to

(in.) Ib/gal kglm3 5,000 7,500 10,000 15,000 20,000 25,000

10 1,198 160 to 320 240 to 320 240 to 400 320 to 560 400 to 640 560 to 7203-1/8

to 14 1,678 240 to 400 320 to 400 320 to 480 400 to 640 480 to 720 560 to 800

418 2,157 400 to 480 480 480 to 560 560 to 720 640 to 800 720 to 880

10 1,198 240 to 480 320 to 560 320 to 560 400 to 640 560 to 800 640 to 8804-1/4

to 14 1,678 320 to 640 400 to 720 480 to 800 480 to 880 640 to 1,040 800 to 1,200

5-1/218 2,157 480 to 720 480 to 800 560 to 880 560 to 960 640 to 1,120 880 to 1,340

10 1,198 480 to 560 560 to 640 560 to 720 640 to 880 720 to 960 800 to 1,1205-3/4

to 14 1,678 560 to 720 640 to 800 640 to 880 720 to 1,200 880 to 1,420 960 to 1,500

718 2,157 640 to 800 640 to 880 720 to 1120 800 to 1,440 960 to 1,520 1,040 to 1,760

10 1,198 640 to 800 720 to 880 800 to 960 1,040 to 1,360 1,200 to 1,600 1,600 to 1,8407-1/2

to 14 1,678 800 to 960 880 to 1,040 960 to 1,200 1,200 to 1,600 1,420 to 1,840 1,760 to 2,160

818 2,157 880 to 1,200 960 to 1,360 1,040 to 1,440 1,280 to 1,760 1,520 to 2,160 1,810 to 2,320

10 1,198 960 to 1,200 1,040 to 1,280 1,120 to 1,280 1,200 to 1,520 1,440 to 1,840 1,840 to 2,3208-1/4

to 14 1,678 1,020 to 1,360 1,200 to 1,440 1,280 to 1,520 1,440 to 1,920 1,520 to 2,000 2,000 to 2,560

918 2,157 1,120 to 1,440 1,280 to 1,520 1,360 to 1,600 1,520 to 2,080 1,600 to 1,560 2,160 to 2,720

10 1,198 1,120 to 1,200 1,200 to 1,280 1,120 to 1,280 1,200 to 1,520 1,440 to 1,840 1,840 to 2,320

10 14 1,678 1,120 to 1,360 1,200 to 1,440 1,280 to 1,520 1,440 to 1,920 1,520 to 2,000 2,000 to 2,560

18 2,157 1,120 to 1,440 1,280 to 1,520 1,360 to 1,600 1,520 to 2,080 1,600 to 2,560 2,160 to 2,720

10 1,198 1,120 to 1,200 1,200 to 1,280 1,120 to 1,280 1,200 to 1,520 1,440 to 1,840 1,840 to 2,320

11 14 1,678 1,120 to 1,360 1,200 to 1,440 1,280 to 1,520 1,440 to 1,920 1,520 to 2,000 2,000 to 2,560

18 2,157 1,120 to 1,440 1,280 to 1,520 1,360 to 1,600 1,520 to 2,080 1,600 to 2,560 2,160 to 2,720

Notes:

For large drill collars with H-90 or 6 5/8-in. regular tool joints, add 200 grains to minimum shot.

Above 10,000 ft in fluid less than 10 Iblgal, do not exceed 100 grains per 00 in.




B ac king O ff

Table 9-String-Shot Strength for Casing and Washpipe



(tt)Pipe


(in.) Ib/gal kglm3

5,000 7,500 10,000 15,000 20,000 25,000

10 1,198 240 to 400240 240 to 320 320 to 480

4-1/2 14 1,678 160 160 to 240

320 to 400

18 2,157 240 to 320 240 to 400 400 to 560

10 1,198 160 to 240 240 320 320 to 400 400 to 4805 160 to 240

a n d 14 1,678 240 480 to 560

5-1/2 240 to 320 320 to 400 400 to 480

18 2,157 160 to 320 240 to 320 480 to 640

10 1,1986 160 to 240 240 to 320 320 to 400 400 to 480 480 to 560 560 to 640

a n d 14 1,678

6-5/818 2,157 160 to 320 320 to 400 400 to 480 480 to 560 560 to 640 640 to 720

10 1,1987 240 to 320 320 to 400 400 to 480 480 to 560 560 to 640 640 to 720

a n d 14 1,6787-5/8

18 2,157 240 to 400 400 to 480 480 to 560 560 to 640 640 to 720 720 to 800

10 1,1988 240 to 320 320 to 400 400 to 480 480 to 560 560 to 640 640 to 720

a n d 14 1,678

8-5/818 2,157 240 to 400 400 to 480 480 to 560 560 to 640 640 to 720 720 to 800

10 1,1989 240 to 320 320 to 400 400 to 480 480 to 560 560 to 640 640 to 720

a n d 14 1,678

9-5/818 2,157 320 to 400 400 to 480 480 to 560 560 to 640 640 to 720 720 to 800

10 1,19810 320 to 400 400 to 480 480 to 560 560 to 640 640 to 720 720 to 800

a n d 14 1,678

10-3/418 2,157 400 to 480 480 to 560 560 to 640 640 to 720 720 to 800 800 to 880




C uttin g th e P ip e

OverviewCutting the pipe is necessary when the geometry of the

wellbore makes it impossible to transmit torque down

to the point of backoff. Cutting the pipe may also be an

economical method of pipe recovery, since it typically

takes less time than backing off.

Various types of pipe-cutting devices are available,

each with advantages and disadvantages. To

determine the type of cutting device to use during the

pipe recovery operation, the capabilities of each device

must be considered from the point of view of the

sticking situation and wellbore conditions. An

experienced pipe recovery crew, familiar with the

advantages and limitations of a variety of cutters, canhelp to select the appropriate tool for the specific

cutting operation. Manufacturers' manuals,

Weatherford's sales staff, and district locations can

provide information about cutter sizes.


Types of CuttersThere are several categories of cutting tools:

• chemical cutters

• jet cutters• radial cutting torches (RCTs)

• split shots

• severing tools

• mechanical cutters

This section describes the advantages and

disadvantages of each type of cutting device.

32



C utting th e P ip e

Chemical CutterAdvantages

• Proven, well-known and accepted technology

• Provides instantaneous flare-free and burr-free cut

• Will not damage adjacent pipe strings

Disadvantages

• Limited use with certain pipe grades, alloys, and

wellbore conditions

• Limited capability for passing through restrictions and

cutting large pipe below the restriction

• Hazardous to operate and transport• Specific safe-handling requirements

• Requires placarded transportation

• Illegal to transport on passenger flights

• Requires radio silence during operations

• Borehole fluid limitations

• Temperature and pressure limitations

Chemical Cutter and Example Cut

Examples of Chemically Cut Pipe





Jet CutterAdvantages

• Proven, well-known and accepted technology

• Provides instantaneous cut

Disadvantages

• Cut is often flared and sometimes split

• Cut pipe may require milling and dressing before it

can be fished

• May leave debris in the wellbore

• Limited capability for passing through restrictions and

cutting large pipe below the restriction• May damage adjacent pipe strings

• Hazardous to transport


• Illegal to transport on passenger flights



Examples of Jet-Cut Pipe

34




Radial Cutting Torch (RCT)Advantages

• Provides instantaneous, flare-free and burr-free cut

• Leaves no debris in wellbore

• Capable of cutting pipe of any alloy, plastic-lined pipe

and scaled pipe

• Capable of passing through restrictions and cutting

large pipe below the restriction

• Capable of operating at temperatures up to 500°F

(200°C) and at high pressures

• Capable of operating at higher temperatures and

higher pressures than chemical cutters or jet cutters

• Features a non-explosive, flammable solid• May be transported without special requirements,

also on passenger flights

• High-pressure tools

Disadvantages

• New, less familiar technology

• Requires perforating the pipe when cutting just

above a plug

The Radial Cutting Torch (RCT)

Example of Pipe Cut with Radial Cutting Torch





Split ShotAdvantages

• Produces cuts with little or no flaring

• Capable of passing through restrictions

Disadvantages

• Split fish top may cause a loose collar to be left in the

hole, possibly hampering milling operations

• May damage adjacent pipe strings



Examples ofDrill Collars and Pipe Cut with Split Shots





Severing ToolAdvantages

• Capable of separating pipe when no other cutting

device will work

• Capable of separating drill collars up to 11 in.

(279.4 mm)

Severing Tool Illustration

Disadvantages

• Not designed to leave a retrievable fish

• Leaves significant amounts of debris in the wellbore

• May only be used in open holes; will destroy adjacent

pipe



Examples of Pipe Cut with Severing Tools





Mechanical CutterAdvantages

• Two basic types:

- Electro-mechanical for use with electric wireline

- Mud motor-powered for use with coiled tubing and

threaded pipe

• Capable of cutting any type of pipe, in any condition

• No hazardous materials

• No special transportation requirements

• No radio silence requirements

Disadvantages

• Slow cutting, labor-intensive

• Leaves cuttings in wellbore

• Limited capability for passing through restrictions

and cutting large pipe below the restriction


Examples ofMechanical Cutters

38



Pipe Recovery Handbook

Simply Productive"

•W e a t h e r l o r d ®Weatherford

fishing - weather ford pipe rec

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