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B.3 Matching StressCheck™ Load Cases

to Recommended Design Load Cases

for Standard Wells

The following StressCheck™ options are recommended for load cases in

designing a standard well. In each instance, the StressCheck™ option is chosen

to match as closely as possible the design recommendations in Chapter 6 –

Tube Loads.

B.3.1 Production Tubing

StressCheck™ cannot design tubing.

B.3.2 Production Casing

The load cases for production casing for a standard well are as follows.

Table B-10. StressCheck™ Load Case Option Recommendations for Standard Well

Production Casing

Load Type Select Comments

Initial Internal: Mud at Shoe Defined on the

Casing Scheme Spreadsheet

External: Use Cementing and

Landing command

Add Undisturbed

Temperature Profile using

the Wellbore/Undisturbed

Temperature Command

Collapse Internal: Full Evacuation

External: Fluid Gradients (w/Pore

Pressure)

Slightly Non-conservative

because of StressCheck™’s

Default Production

Temperature Profile.

Use the Edit tab to Set

Fluids Above and Below

TOC to the Mud Density at

the Casing Point. Do Not

Enable the Pore Pressure in

the Open Hole Option.

Burst Internal: Tubing Leak w/Reservoir

and Completion Fluids Defined in

Production Data

External: Fluid Gradients (w/Pore

Pressure)

Use the Edit Tab to Set

Fluids Above and Below

TOC to the Pore Pressure

Gradient at the Previous

Casing Shoe. Do Not Enable

the Pore Pressure in Open

Hole Option.

B.3.3 Intermediate Casing

The load cases for surface casing for a standard well are as follows:

Table B-11. StressCheck™ Load Case Option Recommendations for Standard Well

Intermediate Casing

Load Type Select Comments

Initial Internal: Mud at Shoe Defined on the Add the Undisturbed

Temperature Profile using

Casing/Tubing Design Manual B-9

October 2005

Load Type Select Comments

Casing Scheme Spreadsheet

External: Use Cementing and

Landing Command

the Wellbore/Undisturbed

Temperature Command

Collapse Internal: Full/Partial Evacuation

External: Fluid Gradients (w/Pore

Pressure)

Use the Edit Tab to Set the

Internal Fluid Density to the

Heaviest Used in the Next

Hole and to Set the Fluid

Level to ½ the TVD to the

Next Casing Point

Use the Edit Tab to Set the

Fluids Above and Below the

TOC to the Mud Density at

the Casing Point. Do Not

Enable the Pore Pressure In

Open Hole Option

Slightly non-conservative

because of StressCheck™’s

Default Circulating

Temperature Profile

Burst Internal: Frac @Shoe w/Gas

Gradient Above

External: Fluid Gradients (w/Pore

Pressure)

Use the Edit Tab to Set the

Frac Margin Of Error to 0,

and to Set the Gas Gravity

to 0.7 (both are

StressCheck™ defaults)

Use the Edit Tab to Set the

Fluids Above and Below the

TOC To Water. Do Not

Enable the Pore Pressure In

Open Hole Option

Burst Internal: Displacement To Gas

External: Fluid Gradients (w/Pore

Pressure)

Ensure that the Buckling

Check Box is Active on the

Design Parameters

Command

Use the Edit Tab to Set the

Mud/Gas Interface Equal to

the Influx Depth. For Mud

Weight, Use the Fracture

Gradient - 0.5 ppg

Use the Edit Tab to Set the

Fluids Above and Below

TOC to the Mud Density At

the Casing Point. Do Not

Enable the Pore Pressure In

Open Hole Option

B.3.4 Surface Casing

The load cases for surface casing for a standard well are as follows.

Table B-12. StressCheck™ Load Case Option Recommendations for Standard Well

Surface Casing

Load Type Select Comments

Initial Internal: Mud at the Shoe is defined

on the Casing Scheme Spreadsheet

External: Use the Cementing and

Add the Undisturbed

Temperature Profile Using

the Wellbore/Undisturbed

B-10 Casing/Tubing Design Manual

October 205

Load Type Select Comments

Landing Command Temperature Command

Collapse Internal: Full/Partial Evacuation

External: Fluid Gradients (w/Pore

Pressure)

Use the Edit Tab To Set the

Fluid Level to Shoe Depth of

the Surface Casing String

(i.e., Complete Evacuation)

Use the Edit Tab to Set the

Fluids Above and Below the

TOC to the Mud Density at

the Casing Point. Do Not

Enable the Pore Pressure In

Open Hole Option

Slightly Non-conservative

because of StressCheck™’s

Default Production

Temperature Profile

Collapse Internal: Cementing

External: N/A

Water will be Used for

Displacement Fluid Only if it

has been Entered as the

Fluid Density at the Surface

Casing Shoe

Slightly Non-conservative

because of StressCheck™’s

Default Production

Temperature Profile

This Option Ignores the

Choice of External Fluid and

Uses the Fluids Defined

Under Cementing and

Landing

Burst Internal: Frac @Shoe w/Gas

Gradient Above

External: Fluid Gradients (w/Pore

Pressure)

Use the Edit Tab to the Set

Frac Margin of Error to 0,

and to Set Gas Gravity to

0.7 (both are StressCheck™

defaults)

Use the Edit Tab to Set the

Fluids Above and Below the

TOC to Water. Do Not

Enable the Pore Pressure In

Open Hole Option

B.4 Matching StressCheck™ Load Cases

to the Recommended Design Load

Cases for HPHT Wells

The following StressCheck™ options are recommended for load cases in

designing an HPHT well. In each instance, the StressCheck™ option is chosen

to match as closely as possible the design recommendations of Chapter 6 –

Tube Loads.

B.4.1 Production Tubing

StressCheck™ cannot design tubing.

Casing/Tubing Design Manual B-11

October 2005

B.4.2 Production Casing

The load cases for production casing for an HPHT well are as follows.

Table B-13. StressCheck™ Load Case Option Recommendations for HPHT Well

Production Casing

Load Type Select Comments

Initial Internal: Mud at Shoe is Defined on

the Casing Scheme Spreadsheet

External: Use Cementing and

Landing Command

Add the Undisturbed

Temperature Profile Using

Wellbore/Undisturbed

Temperature Command

Collapse Internal: Full Evacuation

External: Fluid Gradients (W/Pore

Pressure)

Non-Conservative because

of StressCheck™’s Default

Production Temperature

Profile

Full Evacuation is More

Conservative than the HPHT

Load Case

Use the Edit Tab to Set

Fluids Above and Below the

TOC to the Mud Density at

the Casing Point. Do Not

Enable the Pore Pressure In

Open Hole Option

Burst Internal: Tubing Leak W/Reservoir

and Completion Fluids Defined in the

Production Data

External: Fluid Gradients (W/Pore

Pressure)

Use the Edit Tab to Set

Fluids Above and Below the

TOC to the Pore Pressure

Gradient at the Previous

Casing Shoe

Use the Edit Tab to Enable

Pore Pressure In Open Hole

Option

B.4.3 Intermediate Casing

The load cases for intermediate casing for an HPHT well are as follows.

Table B-14. StressCheck™ Load Case Option Recommendations for HPHT Well

Intermediate Casing

Load Type Select Comments

Initial Internal: Mud at Shoe is Defined on

the Casing Scheme Spreadsheet

External: Use Cementing and

Landing Command

Add the Undisturbed

Temperature Profile Using

the Wellbore/Undisturbed

Temperature Command

Collapse Internal: Full/Partial Evacuation

External: Fluid Gradients (W/Pore

Pressure)

Use the Edit Tab to Set the

Internal Fluid Density to the

Heaviest Used in the Next

Hole and to Set the Fluid

Level to 1/3 the TVD to the

Next Casing Point

Use the Edit Tab to Set the

Fluids Above and Below the

TOC to the Mud Density at

the Casing Point. Do Not

Enable the Pore Pressure In

B-12 Casing/Tubing Design Manual

October 205

Load Type Select Comments

Open Hole Option.

Slightly Non-Conservative

because of StressCheck™’s

Default Circulating

Temperature Profile

Burst Internal: Frac @Shoe w/Gas

Gradient Above

External: Fluid Gradients (w/Pore

Pressure)

Use the Edit Tab to Set the

Frac Margin of Error to 0,

and to Set the Gas Gravity

to 0.7 (both are

StressCheck™ defaults)

Use the Edit Tab to Set the

Fluids Above and Below the

TOC to the Pore Pressure

Gradient at the Previous

Casing Shoe

Use the Edit Tab to the

Enable Pore Pressure In

Open Hole Option

Burst Internal: Displacement to Gas

External: Fluid Gradients (w/Pore

Pressure)

Ensure that the Buckling

Check Box is Active on the

Design Parameters

Command

Use the Edit Tab to Set the

Mud/Gas Interface Equal to

the Influx Depth. For Mud

Weight, use the Fracture

Gradient - 0.5 ppg

Use the Edit Tab to Set the

Fluids Above and Below the

TOC to the Mud Density at

the Casing Point. Do Not

Enable the Pore Pressure In

Open Hole Option

B.4.4 Surface Casing

For HPHT wells, the surface casing is designed using the same load cases

definitions as intermediate casing.

B.4.5 Special Notes

Please note the following items:

• Always enable the Buckling option under Tubular/Design parameters.

• Before performing a Minimum Cost design, the Design tab under

Tubular/Minimum Cost should always be edited to duplicate the figure

below.

Casing/Tubing Design Manual B-13

October 2005

Figure B-9. StressCheck™ Design Tab

• The current version of StressCheck™ populates the design load edit boxes

with values that may not always be correct. Always check these values.

• Always enable the Service Loads option under Tubular/Axial Loads.

• For axial load, in addition to Service Loads, the following additional options

are recommended - Overpull Force (with 450 kN (100000 lb)), Pre-Cement

Static Load, and Post-Cement Static Load.

B.5 CWEAR

The CWEAR series of casing wear models, written by Maurer Engineering as

part of DEA-42, is the only generally available wear predictor. Fortunately,

CWEAR predictions have been shown to be both qualitatively (location) and

quantitatively (value) accurate when compared to field measurements.

CWEAR, like its cousin, DDRAG, is written in Visual Basic

and shares the same

input idiosyncrasies and fatal errors that often result in unanticipated interruptions

of execution. Saving one's data frequently is highly recommended. Nevertheless,

a patient user will find CWEAR a valuable tool for casing wear analysis.

B.5.1 CWEAR Options

Much of the input to CWEAR is straightforward. CWEAR does, however, contain

a number of options to customize a wear analysis. The following

recommendations should be used instead of evidence to the contrary.

B-14 Casing/Tubing Design Manual

October 205

B.5.1.1 Tortuosity (Survey Data)

Tortuosity applies a sinusoidal variation to both inclination and azimuth. Only the

smooth artificial surveys used during well planning should have tortuosity

applied. The following recommendations are taken from the CWEAR user's

manual:

• The period should be at least five times the average interval between

adjacent survey stations.

• Due to the behavior of the sine function, and if the survey stations are

equally spaced from the surface, a period equal to twice the survey

interval will result in no tortuosity.

• The amplitude should be set to 1.0 to model typical field conditions.

B.5.1.2 Dogleg Insertion (Survey Data)

Dogleg insertion shifts the survey on either side of the point of interest and then

uses a new survey station to connect the shifted survey with its original path.

Dogleg insertion is an important option for emulating the casing curvature in a

vertical well associated with helical buckling.

B.5.1.3 Drill Pipe Protector Calculation (Tubular Data)

Several of the entries under Tool Joint Information on the Tubular Data input

window are directly applicable to the calculation of the number of drill pipe

protectors necessary to avoid excessive casing wear.

Table B-15. CWEAR Tubular Data Input Variables

Input Variable Use in CWEAR

Max. Lateral Load per Tool Joint This is the maximum normal force to be tolerated

on a tool joint before protectors are considered. If

the normal force on a tool joint is less than this

quantity, no drill pipe protectors are assumed to

be necessary.

Max. Lateral Load per Drill Pipe

Protector

The maximum normal force each drill pipe

protector can support.

Wear Limit on Drill Pipe Protector

Usage

If the wear is less than this value, no drill pipe

protectors are assumed necessary.

Should drill pipe protectors be necessary, the number of protectors per tool joint

is calculated from the formula:

Pr int

int

otectors per Jo

Normal Force per Tool Jo

Max Lateral Load per Drill Pipe otector

=+1

(B-1)

where the value calculated is rounded down to the nearest integer.

The normal force per tool joint is determined by assuming all the normal force on

a drill pipe joint is supported at the tool joint. If the drill pipe joint length and tool

joint lengths are unknown, recommended values are 30 ft and 14 in.,

respectively.

Casing/Tubing Design Manual B-15

October 2005

B.5.1.4 Calculation Parameters (Tubular Data)

The calculation parameters control the size of the increments used in the wear

calculation. Smaller increments produce more accurate results, but require

longer execution time.

Input Variable Use in CWEAR

Initial Drill Depth The assumed depth of the bit at the start of the

calculation. The initial drill depth and cumulative

length of the drillstring determine the total

calculation interval.

Drill Incremental Int.

The depth interval, over which the normal forces,

etc. used in the wear calculation, is assumed

constant; 1,000 ft is a typical value.

Calculation Int.

For each drill incremental interval, the calculation

interval subdivides the drillstring into elements.

Increments in normal force, etc., are calculated

for each element.

In summary, new calculations of normal force along the string are made for each

drill incremental interval. Each time a new drill incremental interval is started, the

string is divided into a number of elements based on the value of the calculation

interval.

B.5.1.5 Revised Burst and Collapse Resistance

(Parameter Data)

Several options for displaying the effect of wear on collapse and burst resistance

are available. Results from the option selected are displayed in the output

windows following a wear calculation. Recommendations are shown in the

following sub-section.

B.5.1.6 Collapse

Ignore all CWEAR estimates of collapse of worn casing. The reduction in

collapse resistance because of wear is directly proportional to the reduction in

wall thickness. When viewing the output, wear percent can be used to determine

the reduction in collapse resistance.

B.6 Wear and Casing Design Software

Wear constitutes a direct threat to the integrity of affected casing when that

casing is subjected to subsequent differential pressure and/or axial loads.

Usually, the pressure and axial loads associated with the drilling that produces

wear are insufficient to cause failure. It is later loads, associated with well control

or completion and production operations, when coupled with the reduced wall

thickness, that pose the greatest potential for failure.

In later versions of CWEAR this variable is calculated internally.

B-16 Casing/Tubing Design Manual

October 205

Wear is most common in extended reach and horizontal wells where either the

length of rotation or the magnitude of the normal force at a point in the wellbore

becomes critical. Vertical wellbores typical of onshore and exploratory holes are

not, however, without the potential for wear. Here, the culprit is usually buckling,

which produces a curvature in the casing corresponding to the helical trajectory

of the unstable tubular. Common causes of buckling in vertical wellbores include:

• Setting a string on bottom or slacking off during the WOC before allowing

the cement time to build sufficient gel strength to support the casing.

• Changing axial force and effective tension that is associated with

increases in drilling fluid density and circulating temperature during drill

ahead. This source has become prominent in intermediate casing strings

as cement tops are lowered (below the previous shoe) to 1) avoid a

trapped annulus in HPHT wells and/or 2) permit annular cuttings

injection.

Currently, no software contains integrated prediction of both wear and its effect

on exposed tubulars. Working this problem usually involves coordinating two

models, a wear model and a casing design model. The following sections,

following a discussion of the affect of wear on casing integrity, offer guidance in

coordinating the casing design/wear prediction procedure for directional and

vertical wellbores.

B.6.1 Wear in Directional Wellbores

In a directional wellbore, the steps for determining the effect of wear on the

integrity of a casing string are iterative:

1. Design a trial casing string assuming no wear. The string should be sufficient

to withstand all anticipated service loads.

2. Use the trial casing string as input in CWEAR and determine the wear for

anticipated drilling conditions.

3. With a wear prediction in hand, check the integrity of the trial casing string. If

necessary, repeat the procedure with a revised casing string.

Typically, only one iteration will be necessary as wear is relatively insensitive to

the wall thickness and grade of casing

B.6.2 Wear in Vertical Wellbores

The procedure for determining the effect of wear on the integrity of a casing

string in a vertical wellbore is identical to the procedure for a directional wellbore,

with one exception. In a directional wellbore the normal force immediately follows

from the inclination and directional changes of the borehole trajectory. In a

vertical wellbore, however, wear will only occur in the presence of buckling

because there is no normal force coinciding with metal-to-metal contact. It,

StressCheck

™

does contain a utility for computing the maximum allowable wear that a

string can tolerate and still maintain acceptable design factors. There is, however, no

procedure for inputting wear as part of the design process.

Casing/Tubing Design Manual B-17

October 2005

therefore, becomes necessary to fabricate a borehole trajectory from knowledge

of the character of the helically buckled tube. The amended procedure applicable

to a vertical hole is:

1. Design a trial casing string assuming no wear. The string should be sufficient

to withstand all anticipated load cases. Include a drill-ahead load case not to

check for string integrity, but rather to check for the possibility of helical

buckling during drilling operations inside the trial string.

2. If no buckling is predicted in step 1, there is no need to execute a wear

analysis. If buckling is predicted, compute the dogleg severity in the helically

buckled tubular using the procedure described in "Generating a Trajectory

based on Helical Buckling" below.

3. Use the trial casing string as input in CWEAR and determine the wear for

anticipated drilling conditions. Generate a drilling-induced directional

trajectory based on the character of the helix into which the casing is

buckled.

4. With a wear prediction in hand, check the integrity of the trial casing string. If

necessary, repeat the procedure with a revised casing string.

B.6.2.1 Generating a Trajectory Based on Helical

Buckling

When a tube buckles in a vertical wellbore, the curvature of the helix is given by,

=−

(B-2)

where,

c is curvature

is effective tension,

(

)

FF pApA

ez iioo

=− −

(B-3)

r is radial clearance between the tubular and its confining hole

is Young's modulus

is the moment of inertia of the tube cross section,

[]

IDDt=−−

()

(B-4)

where,

is axial force

is local internal pressure

is local external pressure

ADt

=−

()

(B-5)

B-18 Casing/Tubing Design Manual

October 205