chapter 5 -casing

7/24/2019 Chapter 5 -Casing

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CHAPTER 5:

CASING

DRILLING ENGINEERING I

(CGE577)1


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Contents

Definition and function of Casing

Casing Accessories

Types of Casing

Casing Properties Casing Setting Depth/ Casing Seat Selection

Casing Selection: Size Selection and Grade Selection

(Collapse Load, Burst Load, Tensile Load)

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DEFINITION OF CASING

Casing is a steel pipe that iscemented in place in an

openhole wellbore as drillingprogresses to prevent the wall

of the hole from caving induring drilling, to preventseepage of fluids, and to

provide a means of extracting

petroleum if the well isproductive

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FUNCTIONS OF CASING4

1. To keep the hole open and to provide support for weak, vulnerable or fracturedformations.If the hole is left uncased, the formation may cave in and redrillingof the hole will then become necessary.

2. To isolate porous media with different fluid/pressure regimes fromcontaminating the pay zone. This is basically achieved through the combined

presence of cement and casing. Therefore, production from a specific zone canbe achieved.

3. To prevent contamination of near-surface fresh water zones.

4. To provide a passage for hydrocarbon fluids; most production operations arecarried out through special tubings which are run inside the casing.

5. To provide a suitable connection for the wellhead equipment and later thechristmas tree. The casing also serves to connect the blowout preventionequipment (BOPS) which is used to control the well while drilling.

6. To provide a hole of known diameter and depth to facilitate the running oftesting and completion equipment.


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CASING JOINT: Casing joints are connectedusing casing couplings. Generally around 40ft (13 m)in length and is normally designed with male threadedon each ends.The materialthat are usually used tofabricate a casing joints are plain carbon steel, stainlesssteel, aluminum, titanium, fiberglass.

CASING COUPLING/ COLLAR:A short length pipewith female threaded on each ends.

The API standard for casing couplings are

Short round threads and couplings (CSG)

Long round threads and couplings (LCSG)

Buttress threads and couplings (BCSG) Extremelines threads (XCSG)

CASING STRING:A number of casing joints areconnected with casing couplings to form a casing string ofthe desired length and specification

CASING ACCESSORIES- CASING CONNECTION

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Length of Joint

The casing joint length is standardized by API

API Length (source: Drilling Engineering, Herriot-Watt University)

Range Length (ft) Average length

(ft)

1 16-25 22

2 25-34 31

3 34+ 42

CASING JOINT6


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CASING COUPLINGS AND JOINTS

Casing couplingsCasing joints

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Casing shoe/guide shoe is a device thatattached to the bottom of the casingstring.

The casing shoe helped to guide thecasing string to ensure that it is correctlylocated in the wellbore.

The guide shoe includes side ports andan open end to enable fluid circulationfor mud conditioning, hole cleaning, and

cement placement.

CASING SHOE/ GUIDE SHOE8


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CASING HANGER

To suspend or hang casing string which restson a landing shoulder inside the casingspool.

Must be designed to take the full weight ofthe casing and provide a seal between the

casing hanger and the casing spool.

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Lifting-up a Casing

Casing to belifted to the rig

floor

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Making-up a Casing at the Rig Floor

Hydraulic casingtong is used to

make-up the

casing

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Installing Casing

Derrickman is

connecting theelevator to the

top of casing

and lowers into

the hole

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1. Stove Pipe (Marine conductor/ foundation pile foroffshore drilling)

2. Conductor casing

3. Surface casing (BOPs are connected on the top of it)

4. Intermediate casing

5. Production casing

6. Liner casing

Different types/ sizes of casing are needed to seal off the high-pressured zones at different depths along the wellbore, and thepresence of weak, unconsolidated formations or sloughing and shalyzones.

TYPES OF CASING

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CASING CONFIGURATION

Conductor (20 30 OD)

Surface Casing (13- 3/8 20 OD)

Intermediate Casing (9-5/8 16 OD)

Production Casing (4-1/2 9-5/8 OD)

Liner (4-1/2 7 OD)

Casing string is designed such that the largest diameter is run first followed by

smaller diameter casings.

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KINDS OF CASING STRINGS15


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To prevent washouts of near-surface unconsolidatedformations

To provide a circulation system for the drilling mud

To ensure the stability of the ground surface under the rig.

This pipe does not usually carry any weight from thewellhead equipment and can be driven into the ground orseabed with a pile driver.

A typical size for a stove pipe ranges from 26 in. to 42 in.

1. Stove Pipe(Marine-conductor/ Foundation-pile for offshore drilling)

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The largest diameter casing, which is the first to be run

Normally piled to the formation

Installed from surface to a shallow depth to protect near-surface unconsolidated formations (fragile formation) and

provide a circuit for the drilling mud. used to support subsequent casing strings and wellhead

equipment.

Sizes used: 18-5/8 in., 20 in., 26 in. and 30 in.

Generally set at 150 ft to 600 ft below seabed depends onthe formation condition.

In offshore operations, conductor pipes are either driven bya hammer or run in a drilled hole.

2. Conductor Pipe

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Surface casing is run to protect weak formations, water sands andhydrocarbon zones that are encountered at shallow depths.

This casing should be set in competent rocks such as hard limestoneto ensure that formations at the casing shoe will not fracture at thehigh hydrostatic pressures which may be encountered later.

Protect against shallow blow-out, thus BOPs are connected to thetop of it

Support the wellhead and normally set at 1000 ft to 1500 ft belowthe ground level or the seabed.

Cemented to the surface.

Surface casing provides structural strength so that the remainingcasing strings may be suspended at the top and inside of the surfacecasing.

Sizes used: 13-3/8 in, 18-5/8 in and 20 in.

3. Surface Casing

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This casing is set after surface casing and before productioncasing to isolate the lost circulation zones, abnormallypressured zones, mobile salt sections, unstable shale zonesand other troublesome formations between surface and

production casing Set in the transition zone below or above an over-pressured

zone.

Cemented to the surface.

Sizes used: 9-5/8 in or 10- in (depends on thetubing/production casing size).

4. Intermediate Casing

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Represents the last casing string.

Used to isolate producing zones, provide reservoir fluidcontrol, and to permit selective production in multizoneproduction.

The casing string thru which the well will be completed.

Cemented to 200 ft above the topmost HC zone.

Sizes used: 7 in (depends on the tubing/production casingsize).

5. Production Casing

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A liner is a string of casing that does notreach the surface.

Liner is a short casing with length less than

5000 ft and attached to the liner hangerwhich is suspended from the inside of theprevious casing string.

It can act as either intermediate string orproduction string.

The liner is cemented into the previouscasing with liner lap range 200-400ft.

6. Liner Casing

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Types of Liner

1. Production liner Run instead of full production casing

Provide isolation across the producing or injecting zones

2. Tie-back liner

A section of casing extending upwards from top of an existing liner to

the surface and complete the pressure seal during production.

To provide an upper section of casing which had seen no drilling.

3. Scab liner

A section of casing that does not reach the surface

Used to repair existing damaged casing sealed from to and bottom bypackers

4. Scab-tie-back liner

A section of casing extending from the top of an existing liner butdoes not reach the surface.

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Types of Liner23


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Advantages of Liner

Total costs of the production string are reduced due toshorter length

Running and cementing times are reduced

The length of reduced diameter is reduced which allowscompleting the well with optimum sizes of productiontubings.

Complete wells with less weight landed on wellheads andsurface pipe where rig capacity cannot handle full string;when running heavy 9-5/8" casing.

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Disadvantages of Liner

Possible leak across a liner hanger

Difficulty in obtaining a good primary cementation due tothe narrow annulus between the liner and the hole.

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Casing is classified in terms of its size, weight, grade and connection type

Size The size of a casing is given by the outside diameter (O.D) of the casing. The standard sizes are 30, 20, 13 3/8, 9 5/8, 7 and 4.5 The pipe less than 4.5 OD is called the tubing.

Casing Weight The standard weight is specified in weight per unit length The same OD casing may have different weight and different internal diameter. Thus the casing weight indicate the wall thickness of the pipe.

Casing Grade The steel properties of the casing varies widely depending on the chemical

composition. The API grade indicated the chemical composition (letter) and the minimum yield

strength of a casing (number).

CASING PROPERTIES26


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CASING PROPERTIES

Grade Minimum

Yield Strength

(psi)

Minimum

Tensile Strength

(psi)

H-40 40000 60000

J-55 55000 75000

K-55

55000

95000

C-75 75000 95000

L-80 80000 95000

N-80 80000 100000

S-95 95000 110000

P-110 110000 125000

V-150 150000 160000

API Grade for Casing

API defines the yield strength as the tensile stress required to produce a total

elongation of 0.5% of the gage length, as determined by an extensometer.

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CASING SIZES SELECTION

Casing sizes and string configuration are dictated by the size of thesmallest casing string to be run

Once it is known, all subsequent casing and hole sizes are selected

Selection of the smallest casing string is based on operational

considerations Drilling engineer will collate this information from geology, reservoir

engineering and production engineering

The objective of the drilling engineer is to use the smallest casing sizespossible

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The bit size to drill a certain interval must be slightly larger than thecasing OD (Table 7.7)

To drill the lower interval, the bit size must fit inside the casing. in turnsit determines the min size of the second deepest casing string (Table 7.8)

Same process continues

CASING SIZES SELECTION (contd)

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CASING SIZES SELECTION (contd)30

i i C i Si & i Si


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Determining Casing Sizes & Bit Sizes

Production casing 7 in. (specified by production engineer); coupling size = 7.656-in

Bit size to drill a hole in which this casing can be run, 8-5/8-in (Table 7.7)

This 8-5/8-in bit has to pass through the intermediate casing The intermediate casing size through which the above bit would pass, 9-5/8-in (Table

7.8)

Bit size to drill a hole in which the 9 5/8-in casing can be run, 12--in (Table 7.7).

This 12--in bit has to pass through the surface casing

The surface casing size through which the above bit would pass, 13-3/8-in (Table 7.8)

The bit size to drill a hole in which the 13 3/8-in casing can be run, 17- -in (Table7.7)

This 17--in bit has to pass through the conductor pipe

The conductor pipe size through which the above bit would pass, 18-5/8-in (Table 7.8)

The bit size to drill a hole in which the 18 5/8-in conductor pipe can be run, 24-in.

To pass a bit through a casing, the drift diameter has to be greater than the bit size

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Common Bit Sizes to Run Casing Sizes

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Casing Sizes that Allow Bit Sizes to Pass Through

Table 7.8 continued33

CASING SETTING DEPTHS/


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CASING SETTING DEPTHS/CASING SEAT SELECTION

It is essential to choose a casing seat that can withstand themaximum pressures to which the wellbore will be subjected (basedon formation strength/ fracture pressure) during the drilling of thenext hole section.

The pressure which the formation at the casing seat must be able towithstand is the greater of:

(i) the hydrostatic pressure of the mud used to drill the next section

(ii) the maximum pressure exerted at the casing seat when

circulating out gas influx from TD of the next hole section

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CASING SEAT SELECTION METHOD

a) Casing seat selection based on mud weight:

The fracture gradient data together with pore pressureand mud weight should be plotted against depth.

b) Casing seat selection based on Gas Influx Pressures

The fracture gradient data together with pore pressureand maximum kick circulation pressure should be plottedagainst depth.

The selected casing setting depth is then the deeper of thetwo depths arrived at under items (a) and (b) above.

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a) Casing seat selection based on mud weight

1. Plot the pore pressure gradient, the mud pressure gradient and thefracture gradient against depth (Figure 1).

2. Always start at the highest mud weight; in this example the highestmud weight is used at TD.

3. Starting at hole TD (11 000 ft), draw a vertical line (line 1) through

the mud gradient until it intersects the fracture gradient line.

4. In this example the mud gradient at TD is 0.94 psi/ft and a verticalline through it (line 1) intersects the fracture gradient line at 10 500 ft(point A).

5. Above 10,500 ft, the mud gradient, 0.94 psi/ft, will exceed thefracture gradient of the open hole section and this section musttherefore be cased off before raising the mud weight to 0.94 psi/ft todrill the bottom section.

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a) Casing seat selection based on mud weight

6. Between 10 500 ft and 11 000 ft the open hole should be cased with either aproduction liner or a production casing.

7. Above 10 500 ft the hole must be drilled with a mud weight less than 0.94psi/ft.

8. The new mud gradient is obtained by drawing a horizontal line from point A

to the mud gradient line. Point B in gives the new mud gradient as 0.88psi/ft.

9. Move vertically from point B (line 2) until the fracture gradient line isintersected at 8850 ft at point C. Point C establishes the maximum depththat can be drilled before changing to the new mud gradient of 0.88 psi/ft.Hence, between points B and C, an intermediate casing can be set at point B.

10. Another protective casing should also be set at point D, 8850 ft.

11. From point C move horizontally to the mud gradient line to point D, wherethe mud gradient is 0.68 psi/ft.

12. A vertical line from point D (line 3) shows that a hole can be drilled with amud gradient of 0.68 psi/ft to surface without fracturing the formation.

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Figure 1:

Casing seat selection

based on mud weight

b) C i t l ti b d G I fl


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b) Casing seat selection based on Gas InfluxPressures

1. Start at Total Depth (TD) of the well

2. Determine the formation fracture pressure at all points in the well

3. Calculate the borehole pressure profile when circulating out a gasinflux from TD: BHP = Gas column P + SIDP

4. Plot the formation fracture pressure and the wellbore pressure whencirculating out an influx

5. The casing must be set at least at the depth where the two plots cross(Y- See Figure 2). This is the shallowest depth at which the casingcan be safely set. If the casing is set any shallower when drilling thishole section then the formation will fracture if an influx occurs.

6. Repeat steps 2 to 5 moving up the well, with each subsequent stringstarting at the casing setting depth for each string.

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b) C i t l ti b d G I fl


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b) Casing seat selection based on Gas InfluxPressures

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Figure 2

TD


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Exercise : Casing Setting Depth

On graph paper, plot the pore pressure gradient, mud pressure gradient andthe fracture gradient. Propose the casing setting depths and the sizes (use 7

production csg.)

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TVD(ft)

Pore pressre(psi)

Fracture pressure(psi)

3000 1320 2490

5000 2450 4200

8300 4067 6972

8500 4504 7225

9000 5984 7650

9500 6810 8123

10000 7800 9200

11000 10900 12045


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Casing design involves 3 distinct operations:

1. Selection of casing sizes and setting depths (Refer slide 28 40)

2. Define the operational scenarios and consequent loads on the casing

3. Calculate the loads on the casing and select the most suitable casing gradesand weights for a specific operation, both safely and economically.

Casing must be able to withstand maximum load anticipated during

operational scenario (while running the casing, drilling subsequent hole section

and producing life of the well)

Minimal cost can be achieved by using lowest possible wt/ft and lowest

coupling grades combination string

CASING DESIGN42

Define Load Condition


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Define Load Condition(Conductor & Surface Casing)

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(Source: Drilling Engineering, Herriot-Watt University)

D fi L d C diti (I t di t C i )


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Define Load Condition (Intermediate Casing)

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D fi L d C diti (P d ti C i )


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Define Load Condition (Production Casing)

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Common External & Internal Pressures on


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Normal types of external pressures experienced by the casing are: Formation pressures on the section which is not cemented

Weight of mud due to poor cementing job.

Cement slurry pressure

Types of internal pressure experienced by the casing:

Mud to surface

Pressure due to influx when kick happened

Evacuation of the casing

Leakage on production tubing

Common External & Internal Pressures on

experienced by the casing46


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There are three basic loads/forces which the casing is subjected to:1. Collapse

2. Burst

3. Tension

Casing needs to withstand loads applied during installation, drillingprocess and production. They must first be calculated and must bemaintained below the casing strength properties.

Eg: The collapse pressure must be less than the collapse strength of thecasing and so on.

Casing should initially be designed for collapse, burst and tension.Refinements to the selected grades and weights should only beattempted after the initial selection is made.

Design Load Criteria47


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Casing Grades & Strengths

Casing can be selected by properties such as:

Hardness (Casing Grades, e.g. C-75, H-40, J-55, P-110, etc.)

Dimensions

Yield Strength

Collapse Strength

Burst Strength (function of yield strength and pipe dimensions)

Tensile Strength (evaluate pipe body strengths and to selectcouplings for joint strengths)

Usually, the high specification the casing is - the higher the cost.

See Table 3.3 for a wide range of casing grades & sizes with theirstrengths

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Casing Design Safety Factors

A safety margin is always included in casing design, to allow for futuredeterioration of the casing and for other unknown forces which may beencountered, including corrosion, wear and thermal effects.

Design factors are usually used for designing tubulars and are based oncomparing the maximum service load relative to the API minimum yield

strength.

Industry Recommended Safety Factors (Design Factors) from various operator:

Collapse DF = 1.0 1.125Burst DF = 1.0 1.33Tensile DF = 1.0

2.0

Design Factor = Rating of the pipe (Collapse/Burst/Tensile)_____Maximum Expected Service Load (Collapse/Burst/Tensile)

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Collapse load = Maximum external pressure required to collapse aspecimen of casing

Collapse pressure originates from the column of mud used to drill thehole, and acts on the outside of the casing. Since the hydrostaticpressure of a column of mud increases with depth, collapse pressure is

highest at the bottom and zero at the top.

Collapse pressure = External pressure Internal pressure (Equation 1)

1. Collapse Load

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iec PPP

How to measure???

Determine the maximum collapse load that

a casing string will be required to withstand

in the worst case scenario:

Determine the lowest pressure that may be

applied inside the casing and the

corresponding highest realistic external

pressure applied.


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1. Casing is assumed empty due to lost circulation at casing setting depth (CSD) or at TDof next hole.

2. Internal pressure inside casing is zero

3. External pressure is caused by mud/cement/pore pressure in which casing was run in(depends on the load condition).

4. Hence using the above assumptions and applying Equation 1, only the external

pressure need to be evaluated.

Simplified procedure for collapse design:

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External pressuremay be caused by:

Pore pressure

Mud weight

Column of cement

C l l ti f C ll P


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Calculation of Collapse Pressure

Determine Internal Pressu re (Pi)

lowest pressure applied inside the casing = evacuation to atmosphere

Pi = (assume atmospheric pressure & air gradient negligible)

= 0 psi (at surface)

= 0 psi (at top of cement)

= 0 psi (at casing shoe)

Gas Zone

@ 8500ft

Reservoir Press.

= 4000 psi

Gas Gradient

=0.1psi / ft

9-5/8 csg

@8000 ft

Pi Po

Cement top

@ 7000ft

Cement = 15.8ppg

Mix water = 8.5ppg

Mud weight

= 10ppg

Formula:

Pressure (psi) = 0.052 x vertical depth (ft) x

fluid weight (ppg)

Determine Collaps e Pressure (Po - Pi)

Po-Pi = 0 - 0 = 0 psi (at surface)

= 3640 - 0 = 3640 psi (at top of cement)

= 4462 - 0 = 4462 psi (at casing shoe)

Determine External Pressu re (Po)highest realistic external pressure applied = mud & green cement

Po = Weight of fluid in annulus


= 0.052 x 7000 x 10 = 3640 psi (at top of cement)

= 3640 + 0.052 x 1000 x 15.8 = 4462 psi (at casing shoe)

Worst case assumptions:

Empty hole (mud lost in a thief zone)Mud above cement with full density

Full cement density working on casing

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54

Collapse Load Lines


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Burst load = Maximum value of internal pressure required to cause thesteel to yield

In oil well casings, burst occurs when the effective internal pressureinside the casing (internal pressure minus external pressure) exceedsthe casing burst strength.

Burst pressure = Internal pressure External pressure (Equation 2)

2. Burst Load

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How to measure???Determine the maximum burst load that a

casing string will be required to withstand:

Determine the highest pressure that may

be applied inside the casing and the

corresponding lowest realistic externalpressure applied. This gives the worst case

scenario.

eib PPP


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To determine the internal pressure:

Burst pressures occur when formation fluids enter the casing while drilling or producing next hole.The unlimited kick is assumed to enter the well, displace the entire mud and then the well is shut-in the moment the last mud drop leaves the well.

To determine the external pressure:

Regardless of whether the casing is cemented or not, the external load is provided by a column ofsalt saturated water. It assumes all muds and cements behind casing degrade with time to a densityequivalent to salt-saturated water.

At the top of the hole, the external pressure is zero and the internal pressure must be supportedentirely by the casing body. Therefore, burst pressure is highest at the top and lowest at the casingshoe where internal pressures are resisted by the external pressure originating from fluids outside thecasing.

In production casing the burst pressure at shoe can be higher than the burst pressure at surface insituations where the production tubing leaks gas into the casing.

Simplified procedure for burst design:

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Internal pressuremay be caused by:

Hydrocarbon influx

Tubing leak

Calculation of Burst Press

ure


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Determine Internal Pressu re (Pi)

highest pressure applied inside the casing = evacuation to gas

Pi = Reservoir Pressure - weight of gas column

= 4000 - 8500 x 0.1 = 3150 psi (at surface)

= 4000 - 1500 x 0.1 = 3850 psi (at top of cement)

= 4000 - 500 x 0.1 = 3950 psi (at casing shoe)

Gas Zone

@ 8500ft

Reservoir Press.

= 4000 psi

Gas Gradient

=0.1psi / ft

Pi

Po

Cement top@ 7000ft

Cement = 15.8ppg

Mix water = 8.5ppg

Mud weight

= 10ppg

Formula:

Pressure (psi) = 0.052 x vertical depth (ft) x

fluid weight (ppg)

9-5/8 csg

@8000 ft

Determine Bu rst Pres sur e (Pi - Po)

Pi-Po = 3150 - 0 = 3150 psi (at surface)

= 3850 - 3094 = 756 psi (at top of cement)

= 3950 - 4082 = 414 psi (at casing shoe)

Determine External Pressu re (Po)

lowest realistic external pressure applied = mud & cmt mix water

Po = Weight of fluid in annulus


= 0.052 x 7000 x 8.5 = 3094 psi (at top of cement)

= 3094 + 0.052 x 1000 x 8.5 = 3536 psi (at casing shoe)

Calculation of Burst PressureWorst case assumptions:

Hole filled with gas from gas zone

Mud above cement degrades to saline waters

Saline water between cement & casing

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58

Burst Load Lines


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Selecting the Right Casing for Burst & Collapse Pressures

From Examp le:

Burst Required = 3150 x 1.1 safety factor = 3465 psi

Collapse Required = 4462 x 1.0 safety factor = 4462 psi

From table of 9-5/8 casing types:

Grade Weight Drif t ID Collaps e Bur st Tens ile Cost

K55 40 #/ft 8.68 in. 2570psi 3950psi 630 klb lowest

N80 43.5 #/ft 8.60 in. 3810psi 6330psi 1005 klb

N80 47 #/ft 8.53 in. 4750psi 6870psi 1086 klb

N80 53.5 #/ft 8.38 in. 6620psi 7930psi 1244 klb

P110 43.5 #/ft 8.60 in. 4430psi 8700psi 1381 klb highest

Select this ?

need to check if tensile strength is OK for this choice

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EXAMPLE 7 P d ti C i


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EXAMPLE 7 Production Casing

Collapse Load assume that:

Casing is totally evacuated due to

gas lifting operations (Fullevacuation)

Casing empty

Fluid SG outside pipe is the mud SG

Beneficial effect of cement is ignored

Design Factor of 1.0

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psiPe 0095.17052.0 Collapse Load at Surface:

psiPi 0

psiPPP iec 0

Collapse Load at Casing Shoe:

psiPe 177351900095.17052.0

From Table 3.3, all grade satisfy the requirement.

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psiPi 0

EXAMPLE P d ti C i


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Burst Load assume that:

At Surface

Well has a BHP equal to the formation porepressure/ reservoir pressure and the producing fluidis gas.

A gas leak occurs (0.1 psi/ft) in the production

tubing at surface The CITHP/ shut in pressure is acting on the inside

of the top of casing. This pressure will then act onthe column of packer fluid.

At shoe

Packer Fluid density inside casing/tubing annulus isthe mud density

Fluid density outside casing is the saturated saltwater density (gradient 0.465 psi/ft)

Design Factor of 1.1

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EXAMPLE P d ti C i


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psiPe 0094.8052.0

Burst Load at Surface:

psi

Pi

15341

190001.019000052.045.17

psiPi 330761534119000052.095.17

psiPPP eib 24241

Pi= Shut in BHP Pressure due to Gas Column

psiPPP eib 15341

Burst Load at Casing Shoe:

psiPe 88351900094.8052.0

Pi= Pressure due to Packer Fluid Column + Surface

Pressure due to gas leak

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From Table 3.3, grade V-150 & SOO-155 meet the burst requirement.

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

0 5000 10000 15000 20000 25000 30000

Pc

Pb

V-150 38#

V-150 41#

V-150 46#

MW-155

SOO-140

SOO-155

64

need to check if tensile strength is OK for this choice

T il / T i L d


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3. Tensile/ Tension Load

Most axial tension arises from the weight of the casing itself. Othertension loadings can arise due to: bending, drag, shock loading andduring pressure testing of casing.

In casing design, the uppermost joint of the string is considered theweakest in tension, as it has to carry the total weight of the casingstring.

The total surface tensile load (sometimes referred to as installationload) must be determined accurately and must always be less than theyield strength of the top joint of the casing.

The installation load must be less than the rated derrick load capacityso that the casing can be run in or pulled out of hole without causingdamage to the derrick.

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Si lifi d d f T i d i


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Simplified procedure for Tension design:

1. Calculate weight of casing in air using true vertical depth

2. Calculate buoyancy force (BF) and buoyant weight (wet weight)

Wet Weight/ Buoyant weight = Casing air weight x BF

3. Calculate bending force in deviated wellsWhere:

3. Calculate drag force in deviated wells (this force is only applicable ifcasing is pulled out of hole) = usually of the order of 100,000 lbf

4. Calculate shock loads due to arresting casing in slips

5. Calculate pressure testing forces =

Forces (1) to (3) always exist, whether the pipe is static or in motion.Forces (4) and (5) exist only when the pipe is in motion.

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Buoyancy Factor (BF) = (65.5 mud weight in ppg) 65.5

Calculation of total tensile load


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LoadTensileTotal

YSF

p

Yp= Joint/ body yield strength

In the initial selection of casing, check that the casing can carry its own weight inmud and when the casing is finally chosen, calculate the total tensile loads andcompare them with the joint or pipe body yield values, using the lower of the twovalues.

A design factor (1.6 to 1.8) of coupling or pipe body yield strength divided bytotal tensile loads in tension should be used.

Total Tensile Load = Cumulative Wet Weight carried by top joint + Shockload +bending force + drag force + pressure testing force

Calculated Safety Factor, SF should exceed the specified SF (1.6 to 1.8).

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Calculation of total tensile load

Tensile Load EXAMPLE


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7 Production CasingCheckfor tensile loading (SF=1.8):

Assume vertical well and only shock load is considered

Wet Weight

From To (BF=0.726)

0 6000 V-150 38# 6000 1430 38 165528 564828 121600 686428 2.083248

6000 12000 MW-155 6000 1592 38 165528 399300 121600 520900 3.05624912000 19000 V-150 46# 7000 1344 46 233772 233772 147200 380972 3.527818

SFDepth (ft) Total

TensileGrade Length Yp (1000 lb) Wn (lb/ft)

Total Wet

Weight

Shock

Load

Since calculated SF exceed minimum SF of 1.8, all sections satisfytensile load requirement.

Need to check for costs.Where:

Wet Weight/ Buoyant weight = Wn x Length x BF

Shockload = 3200 x Wn (Nominal weight)

Yp = Joint yield strengthLoadTensileTotal

YSF

p

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Buoyancy Factor (BF) = (65.5 mud weight in ppg) 65.5


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chapter 5 -casing

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