StressCheck

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Software,

Release 5000.1.13

Training Manual

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Note

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Chapter 1: Introduction

. . . 1-1 What is the StressCheck™ Software? . . . 1-1 Course Objectives . . . 1-2 Training Course and Manual Overview . . . 1-3 Licensing. . . 1-3

Chapter 2: Theory, Calculations, and References

. . . 2-1

Casing Design Methodology

. . . 2-2

Wellbore Temperatures and Casing Design

. . . 2-4 Temperature Deration . . . 2-4 Drilling Temperatures. . . 2-5 Production Temperatures . . . 2-6 Initial Conditions . . . 2-7

Basic Material Properties

. . . 2-9 Stress . . . 2-9 Strain . . . 2-9 Modulus of Elasticity (Young’s Modulus) . . . 2-9 Yield Strength (Tensile) . . . 2-10

Pipe Ratings

. . . 2-11 Axial . . . 2-11 Burst . . . 2-12 Collapse . . . 2-12 Yield Strength Collapse . . . 2-13 Plastic Collapse. . . 2-13 Transition Collapse . . . 2-14 Elastic Collapse. . . 2-14 Diameter to Wall Thickness Regions . . . 2-15 Effect of Tension on Collapse . . . 2-16

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Tension due to Bending . . . 2-19

Triaxial Stress Analysis

. . . 2-20 Von Mises Equation . . . 2-20 Triaxial Design Ellipse . . . 2-21

Buckling

. . . 2-23 Casing Buckling in Oil Field Operations . . . 2-24

API Connection Ratings

. . . 2-25

Preliminary Design

. . . 2-26 Why Should You Do A Preliminary Design?. . . 2-26 What Data is needed to perform a Preliminary Design? . . . 2-26 Minimum Casing Diameter . . . 2-26 Minimum Casing Shoe Setting Depth . . . 2-27

Detailed Mechanical Design

. . . 2-28 Burst Loads . . . 2-28 Drilling Loads . . . 2-28 Production Loads . . . 2-36 Collapse Loads . . . 2-38 Drilling Loads . . . 2-38 Production Loads . . . 2-41 Axial Loads. . . 2-43 Running and Cementing . . . 2-43 Service Loads . . . 2-46 Load Lines . . . 2-46 Automatic Load Generation . . . 2-46 Design Factors . . . 2-47 Design Factor Selection . . . 2-47 Graphical Design . . . 2-48 Load Line Corrections . . . 2-48

External Pressure Profiles

. . . 2-50 Mud and Cement Mix-Water . . . 2-50 Permeable Zones. . . 2-51 Poor Cement Disabled . . . 2-51 Poor Cement Enabled – High Pressure Zone . . . 2-52 Poor Cement Enabled—Low Pressure Zone . . . 2-53 Minimum Formation Pore Pressure . . . 2-54

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TOC Inside Previous Shoe . . . 2-54 TOC in Open Hole (with and without Mud Drop Enabled) . . . 2-55 Pore Pressure w/ Seawater Gradient . . . 2-56 Fluid Gradients w/ Pore Pressure . . . 2-57 Mud and Cement Slurry . . . 2-58 Frac @ Prior Shoe with Gas Gradient Above. . . 2-59 Shoe/Mud Gradients w/ Pore Pressure . . . 2-59 Hydrostatic Isolation Depth . . . 2-61

Chapter 3: EDM

™

and the Well Explorer

. . . 3-1

Overview

. . . 3-2

Describing the Data Structure

. . . 3-3 Well Explorer Components . . . 3-4

Working with the Well Explorer

. . . 3-6 Drag-and-drop Rules. . . 3-6 Instant Design . . . 3-6 Import . . . 3-7 Export . . . 3-8 Attachments . . . 3-9 Well Explorer Node Properties. . . 3-11 Data Locking. . . 3-11 General Tab. . . 3-13 Audit Tabs. . . 3-14

Datums

. . . 3-15 Project Properties . . . 3-15 System Datum. . . 3-15 Elevation . . . 3-15 Well Properties . . . 3-15 Depth Reference Datum(s) . . . 3-16 Design Properties . . . 3-19 General Tab (Design Properties Dialog Box). . . 3-19 Depth Reference Information . . . 3-20 Workflow—How to Set Up Datums for a Design . . . 3-20

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Concurrency and Multi-user Support

. . . 3-24 SAM in the Application Status Bar . . . 3-24 SAM in the Well Explorer . . . 3-25 Reload Notification. . . 3-26 Reload . . . 3-26 Ignore . . . 3-26 Cancel . . . 3-27

Working with Catalogs

. . . 3-28

Chapter 4: Getting Started

. . . 4-1

Workflow

. . . 4-2 Enter General Data . . . 4-2 Specify Design Parameters for a Casing String . . . 4-3 View Graphical Results and Perform Design . . . 4-3

Getting Started

. . . 4-5 Starting the StressCheck™ Software . . . 4-5

Files and Templates

. . . 4-7 What Type of Files Does the StressCheck™ Software Use? . . . 4-7 What is a Template File? . . . 4-7 Opening an Existing Template File . . . 4-8 Saving a Template File . . . 4-9

Main Window Layout

. . . 4-10 Title Bar . . . 4-11 Menu Bar . . . 4-11 File Menu . . . 4-11 Edit Menu . . . 4-11 Wellbore Menu . . . 4-11 Tubular Menu . . . 4-11 View Menu . . . 4-12 Composer Menu . . . 4-12 Tools Menu . . . 4-12 Window Menu . . . 4-12 Help Menu . . . 4-12 Wizard Toolbar . . . 4-12

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Data Entry Forms

. . . 4-13 Dialog Box . . . 4-13 Spreadsheets . . . 4-14

Helpful Features

. . . 4-15 Online Help. . . 4-15 Setting Options . . . 4-16 Design Plots Group Box . . . 4-16 Spreadsheets and Tables Group Box . . . 4-17 Print Layout Group Box . . . 4-18 Depths Group Box . . . 4-19 Safety Factors Group Box. . . 4-19 MMS Report Group Box . . . 4-19 Other Group Box . . . 4-20 Configuring Units . . . 4-21 Using the Unit System Dialog Box. . . 4-21 Using the Convert Unit Dialog Box . . . 4-22 Using the Convert Unit Dialog Box . . . 4-24 Customizing Graphical Views . . . 4-26 Changing Plot Properties . . . 4-27 Zooming . . . 4-28 Configuring the Well Schematic. . . 4-28

Accessing and Managing Pipe Inventory

. . . 4-29 Selecting and Deleting Pipes . . . 4-31 Modifying Existing Pipes . . . 4-33 Inserting a New Pipe. . . 4-34 Tubular Properties. . . 4-34 Locking Tubular Properties and Password Security. . . 4-35 Importing and Exporting Tubular Properties . . . 4-36 Grades . . . 4-36 Materials . . . 4-38 Class . . . 4-40 Temperature Derations . . . 4-41

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Design Properties Dialog Box . . . 5-2 Entering General Well Information . . . 5-6 Field and Controls. . . 5-7 Entering Pore Pressure Data . . . 5-8 Pore Pressure Spreadsheet Columns. . . 5-9 Entering Fracture Gradient Data. . . 5-10 Fracture Gradient Spreadsheet Columns . . . 5-11 Defining a Squeezing Salt/Shale Zone . . . 5-12 Squeezing Salt/Shale Spreadsheet Columns. . . 5-12 Managing Wellpath Data . . . 5-14 Entering Wellpath Data . . . 5-14 Import Wellpath File. . . 5-15 Dogleg Severity Overrides Spreadsheet . . . 5-16 Defining the Geothermal Gradient . . . 5-19 Fields and Controls . . . 5-19 What Effect Does Temperature Have on the Analysis? . . . 5-21 Define the Casing and Tubing Scheme. . . 5-22 Fields and Controls . . . 5-23 Well Schematic . . . 5-27 Defining Production Data . . . 5-28 Fields and Controls . . . 5-28 Setting Up Tabs . . . 5-29 Splitting Windows into Panes. . . 5-30 Splitting the Tab into Vertical Panes . . . 5-31 Splitting the Tab into Horizontal Panes . . . 5-31 Changing the Contents of the Pane. . . 5-31

Chapter 6: Tubular Load Data

. . . 6-1

Entering Design Parameters

. . . 6-2

Specifying the Initial Conditions

. . . 6-4 Defining Cementing and Landing Data . . . 6-4 Fields. . . 6-5 Defining the Starting Temperature Profile . . . 6-11

Specify Tool Passage Requirements

. . . 6-13

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Selecting the Design Burst Loads and the External Pressure Profile . . . 6-16 Defining the External Pressure Profile . . . 6-16 Defining Burst Load Details . . . 6-17 Using the Multiple tab . . . 6-17 Viewing the Associated External Pressure Profile . . . 6-19 Specify Burst Load Temperature . . . 6-20 View Burst Load Pressure Plots . . . 6-22 Burst Design Load Line . . . 6-23

Specifying Collapse Loads

. . . 6-24 Selecting Collapse Loads . . . 6-24 Selecting Different External Pressure Profiles for Each Load Case. . . 6-25 Defining Collapse Load Details . . . 6-25 Viewing Collapse Load Pressure Plots . . . 6-26 Collapse Design Load Line. . . 6-27

Specifying Axial Loads Details

. . . 6-29

Defining Custom Loads

. . . 6-30 Displaying the List of Existing Custom Loads . . . 6-30 Renaming a Custom Load. . . 6-31 Editing Custom Load Data . . . 6-31 Define the Pressure Profile . . . 6-31 Including the Custom Load in the Analysis . . . 6-33 Defining the Custom Load Temperature Profile . . . 6-33 Viewing the Pressure Profiles Including the Custom Load . . . 6-35

Chapter 7: Graphical Design

. . . 7-1

Performing an Automated Design

. . . 7-2 Checking Burst Design Using the Burst Design Plot . . . 7-2 Creating a Pipe Section. . . 7-3 Modifying a Pipe Section . . . 7-6 Comparing Burst and Collapse Design Checks . . . 7-8 Checking Collapse Design Using the Collapse Design Plot. . . 7-8 What is the Collapse Design Load Line? . . . 7-9 What is the Pipe Rating Line? . . . 7-9

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Using the Axial Load Profiles Plot . . . 7-13 Using the Axial Service Load Profiles Plots . . . 7-14 Using the Service Load Lines Plot . . . 7-15 Checking Axial and Triaxial Design . . . 7-16 Using the Axial Design Plot . . . 7-16 Using the Triaxial Design Plot . . . 7-18 Using the Triaxial Design Limit Plot . . . 7-22 Modify a Design . . . 7-23

Checking a Specific Casing Design

. . . 7-24 Compressional Load Check . . . 7-25

Minimum Cost Design

. . . 7-27 Fields and Controls . . . 7-27 Maximum Number of Sections. . . 7-27 Minimum Section Length . . . 7-27 Cost of K-55 Steel. . . 7-27 Minimum Cost Search . . . 7-29 Select API and Premium Connections . . . 7-30 Define Premium Connections . . . 7-32

Chapter 8: Analyzing Tabular Results and Reports

. . . 8-1

Input Data Tables

. . . 8-2

Tabular Results

. . . 8-3 Viewing the String Summary . . . 8-4 What is the Maximum Allowable Wear? . . . 8-5

Reporting in the StressCheck™ Software and Microsoft Word

. . . 8-8 Generating StressCheck™ Software Reports . . . 8-8 Previewing and Printing StressCheck™ Software Reports . . . 8-11

Chapter 9: Exercises

. . . 9-1

StressCheck™ Software Exercise Overview

. . . 9-2

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Exercise 2: Preferences and Workspace Configuration

. . . 9-5 Exercise 2 Answers. . . 9-7

Exercise 3: Reviewing/Specifying General Data

Exercise 4: The Design Process

Exercise 5: Minimum Cost

Exercise 6: Analyzing Results

Exercise 7: Tables and Reports

Exercise 8: Sensitivity Analysis

. . . 9-86 Special Pipe Tubular Properties . . . 9-86 Exercise 8 Answers: Special Pipe Tubular Properties . . . 9-91 Taper String Design Check. . . 9-99 Exercise 8 Answers: Taper String Design Check . . . 9-100 High Collapse Casing . . . 9-108 Exercise 8 Answers: High Collapse Casing . . . 9-110

Exercise 9: Independent Exercise

. . . 9-114

Exercise 10: Template Exercise

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Introduction

What is the StressCheck

™

Software?

The Landmark® StressCheck™ software is an extraordinarily powerful and easy-to-use engineering tool for the design and analysis of casing strings.

The StressCheck™ software was developed in cooperation with several major oil and gas exploration and production companies as one

component of a next-generation system for well engineering. It is based on casing design principles that are well accepted and broadly employed in the industry. With the StressCheck software, sophisticated design methods can be routinely employed to develop minimum-cost, high-integrity casing design solutions with minimum expenditure of time and effort.

The StressCheck software can be used to design casing strings that meet or exceed all relevant design criteria from top to bottom. The

StressCheck software can yield significant savings in total casing costs by providing a variety of automated formulations for specifying realistic burst, collapse, and axial loads, rather than traditional worst-case maximum load profiles, and by optimizing the number and length of casing string sections. In some cases, as much as 40% can be saved in comparison to casing designs developed by conventional methods. With the Custom Loads feature, the StressCheck software also provides an easy-to-use spreadsheet facility for specifying, in exact detail,

user-defined internal pressure, external pressure, and temperature profiles when more unique load-case formulations are required. Experienced engineers who understand the requirements of casing design developed the StressCheck software with features that facilitate thorough consideration of more sophisticated design issues. These issues include:

• Running, installation, and service loads, for more comprehensive axial design

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• Permeable zones

• Mud density deterioration • Annulus mud drop

• Worst-case or user-entered temperature profiles

• Temperature-dependent and pressure-dependent gas-density profiles

• Overpull limits • Allowable wear • Pressure testing

• Automated Minimum Cost API or triaxial design

The StressCheck software offers OLE to Microsoft™ Office

applications such as Word, Excel, and PowerPoint, as well as other OLE-compliant products. The StressCheck software includes powerful and flexible unit systems, both standard (API and SI) and user-defined, which make it easy to customize input and output unit conventions to suit virtually any international need. The StressCheck software can be used in combination with the powerful Landmark WELLCAT™ package to solve the toughest design problems.

Course Objectives

During this course you should become familiar with: • Fundamental casing design principles

• Equations used to calculate casing ratings • Design criteria and data entry

• Casing design and design checks • Documenting and analyzing results

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Training Course and Manual Overview

The purpose of this manual is to provide you a reference for entering data and performing an analysis during the class. Perhaps more importantly, you can refer to it after the class is over to refresh your memory concerning analysis steps. This manual contains technical information concerning the methodology and calculations used to develop the StressCheck software. If you require more technical information than what is presented in this manual, please ask your instructor.

The training course begins with a quick introduction. Following the introduction, time is spent covering the theory, concepts, and features used in the StressCheck software.

Licensing

For information regarding Licensing, please refer to the Help > Engineer’s Desktop Drilling Summary Level Release Notes > Licensing.

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Theory, Calculations, and References

This section covers the fundamental theory basis for StressCheck™ software calculations and includes the design methodologies considered for workflows.

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Casing Design Methodology

The following displays a list of StressCheck features in a basic workflow that follows a casing design methodology.

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Wellbore Temperatures and Casing Design

Temperatures affect casing design in the following ways: • Influence pressure loads (PVT properties of gas)

• Decrease the pipe rating (the yield strength is a function of temperature)

• Result in axial thermal growth, which can lead to buckling in uncemented sections and may require triaxial analysis to determine combined loading effects

• Affect cement slurry design

• Result in annular pressure build-up • Influence corrosion

Temperature Deration

A default schedule is provided in the StressCheck software that is based on a linear deration of 0.03% per degree °F.

Wellbore temperatures during drilling, completion, production, and workover operations can vary considerably from the undisturbed profile. The StressCheck software uses worst-case estimates by default. To accurately predict wellbore temperatures, a thermal simulator such as the WELLCAT™ software is required.

Temperature Yield Strength Fahrenheit (°F) Celsius (°C) Correction Factor

68 20 1.00

122 50 0.983

212 100 0.956

302 150 0.929

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Drilling Temperatures

For drilling load cases such as a gas kick or lost returns with mud drop, the profile used to correct the design load line is based on the calculated API circulating temperature and a straight line drawn through the midpoint of the user-entered undisturbed temperature profile.

The calculation of the API circulating temperature is generally over-conservative. If a more accurate profile is necessary, thermal simulation using WELLCAT - Drill should be used.

Undisturbed Temperature Profile Drilling Temperature Profile Mid-point of Undisturbed Profile API Circulating Temperature Depth Temperature

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Production Temperatures

For production load cases such as a tubing leak, the profile used to correct the design load line is based on maximum undisturbed reservoir temperature at the perforation depth from TD to the surface.

This profile is generally over conservative depending on reservoir fluid, flow rates, and time after initial production. If a more accurate profile is necessary, thermal simulation using WELLCAT - Prod should be used.

Undisturbed Temperature Profile Production Temperature Profile Depth Temperature

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Initial Conditions

The temperature used in the StressCheck software does not necessarily lead to more conservative design. This data is used to define load cases, determine the initial state of the casing, and dictate design and

analysis logic.

Initial conditions data is defined on a per-string basis; that is, different initial conditions data can be defined for each string in the Casing Scheme spreadsheet. Depth Temperature TOC Surface Ambient StressCheck StressCheck SCK UNCONSERVATIVE

injection temp production temp

dT

Actual

Actual SCK

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The WELLCAT software can simulate a more accurate temperature profile for both production and injection, which can lead to a less conservative design criteria.

Depth

Temperature

TOC Surface

Ambient

injection temp production temp

WellCat StressCheck

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Basic Material Properties

To define a material, the Young’s Modulus, Poisson’s Ratio, and density must be specified. Young’s Modulus (ratio of stress and strain) and Poisson’s Ratio (ratio of lateral contraction to elongation) are the two independent parameters that describe the mechanical behavior of an elastic material.

Stress

• The symbol for stress is:

σ

• Stress is defined as: Load / Cross-sectional area • You can compare stress with: Pressure = Force/Area

Strain

• The symbol for strain is:

ε

• Strain is defined as: Change in Length / Initial Length or

• You can define True Strain as: Ln (Final Length / Initial Length). True strain accounts for the material volume.

Modulus of Elasticity (Young’s Modulus)

The symbol for Modulus of Elasticity is .

For any material, is a constant which relates stress and strain as long as they are proportional. (that is, a straight line graph).

E

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Yield Strength (Tensile)

Yield strength is the stress above which irreversible plastic deformation occurs.

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Pipe Ratings

Axial, Burst, and Collapse loads are factors that directly affect the performance ratings for the selected pipe or connection. Other factors that affect pipe ratings include reduced wall thickness and tension due to bending.

Axial

The axial strength of the pipe body is determined by the pipe body yield strength formula found in API Bulletin 5C3. Axial strength is the product of the cross-sectional area and the yield strength. Nominal dimensions are used.

Where:

F_y = pipe body axial strength, lb

Y_p = minimum yield strength of the pipe, lb/in2

D = nominal outside diameter, inches d = nominal inside diameter, inches

F

_y

π

4 ---

(

D

2

–

d

2

)Y

_p

=

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Burst

The following equation is commonly called the Barlow Equation and is applicable to thin wall pipes. It assumes that burst is imminent when the pipe begins to yield. The factor 0.875 appearing in the equation allows for minimum acceptable wall thickness due to piercing operations as per API specification 5CT.

Where:

P = minimum internal yield pressure, lb/in2

t = nominal wall thickness, inches D = nominal outside diameter, inches

Collapse

As per API Bulletin 5C3, collapse criteria consists of four collapse regimes. These regimes are determined by yield strength and D/t. Most oil field tubulars experience collapse in the plastic and transition regimes. Nominal dimensions are used in the collapse equations. Collapse strength is primarily a function of the material’s yield strength and the D/t ratio. Collapse strength as a function of D/t is shown in the preceding graphic.

P

0.875 2Y

p

t

D

---=

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Yield Strength Collapse

Yield strength collapse is based on yield at the inner wall using the Lamé thick wall elastic solution.

Where:

Plastic Collapse

Plastic collapse is based on empirical data from 2,488 tests.

Where:

P

_Y p

2Y

p

D t

⁄

(

) 1

–

D

t

---- 

 

2

---=

P

_p

Y

_p

A

D t

_⁄

---

–

B

–

C

=

A 2.8762 (0.10679×10–5)YP 0.21301 10 – ×10 ( )YP2 0.53132 16 – ×10 ( )YP3 – + + = B = 0.026233+(0.50609×10–6)YP C = –465.93+0.030867Y_P+(0.10483×10–7)Y2_P–(0.36989×10–13)Y_P3

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Transition Collapse F 46.95×106 3B A ---2 B A ---    + ---3 Y_P 3 B A ---    2 B A ---    + --- B A ---    – 1 3 B A ---    2 B A ---    + ---          – 2 ---= G FB A ---=

Transition collapse is a numerical curve fit between the plastic and elastic regimes.

Where:

(A and B are defined in the section on Plastic Collapse.)

Elastic Collapse

Elastic collapse is based on theoretical elastic collapse. This criteria is independent of yield strength and applicable to very thin wall pipe.

P

_T

Y

_p

F

D t

_⁄

---

–

G

=

P

_E

46.95 10

6

×

D t

_⁄

(

) D t

(

⁄

) 1

–

)

2

---=

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Where:

Diameter to Wall Thickness Regions

The four API collapse regimes depend on the diameter to wall thickness (D/t) ratio of the pipe of interest. Therefore:

Yield Collapse D t ----    D t ----    YP ≤ Plastic Collapse D t ----    YP D t ----    < _{ } D----_t PT ≤ Transition Collapse D t ----    PT D t ----    < _{ } D----_t TE ≤ Elastic Collapse D t ----    D t ----    TE > Where: D   A 2– ( )2 8 B C Y_P ---+     1 2 ---+ +(A 2– )

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D t ----    PT Y_P(A F– ) C Y+ _P(B G– ) ---= D t ----    TE 2 B A ---+ 3B A --- ---=

(A, B, C, F, and G are defined in the sections discussing Transition and Plastic Collapse.)

Effect of Tension on Collapse

The biaxial effect of tension is incorporated in design by reducing the design rating of the pipe. The reduced yield strength equation is based on the Hencky-Von Mises maximum strain energy of distortion theory of yielding or triaxial analysis. In this case, the radial stress is ignored. This theory only applies to elastic yield failure (the yield collapse regime), but the reduction is applied to all the collapse regimes. This tends to be a conservative assumption. The collapse rating is not increased with compression.

Where:

Y_pa = yield strength of axial stress equivalent grade, lb/in2

S_a = axial stress, tension is positive, lb/in2

Effect of Internal Pressure on Collapse

The biaxial effect of internal pressure (radial stress) is incorporated in design by increasing the design rating of the pipe. The API chose to increase the apparent applied collapse pressure instead of including P₀ and P₁ in the collapse formulations. (They are only a function of ΔP). For all collapse loads, P_e>= DΔP

Y

_pa

1 0.75

S

a

Y

_p

--- 

 

 

2

–

0.5 S

a

Y

_p

---–

Y

_p

=

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This relationship can be derived for Hencky-von Mises and Lamé, if higher order terms are ignored.

Where:

t = nominal wall thickness, inches D = nominal outside diameter, inches P_e = equivalent external pressure, lb/in2

P_o = external pressure, lb/in2

P_i = internal pressure, lb/in2

ΔP = Po- Pi

To provide a more intuitive understanding of this relationship, the equation can be rewritten as:

P_eD = P_oD - P_id

Where:

d = nominal inside diameter, inches

Pi Po



P = 0 Pe

P

_e

P

_o

1

2 D t

_⁄

---–

P

_i

–

ΔP

2 D t

_⁄

---





_{ P}

i

+

=

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Reduced Wall vs. Nominal Dimensions

Axial uses nominal dimensions. The piercing process during manufacture may result in non-uniform wall thickness, but the

cross-sectional area of the pipe will remain constant. The equation used in API Bulletin 5C3 to define the axial rating is based on the product of the cross-sectional area and the yield strength.

Burst uses minimum section. This represents a permissible 12.5% wall loss due to acceptable tolerances in the piercing and rolling process of manufacturing seamless pipe. (API Spec. 5CT).

Collapse uses nominal dimensions. The API formula for plastic, transition, and elastic collapse have been adjusted using regression analysis to account for API tolerances. No adjustment has been made in the yield strength collapse regime.

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Tension due to Bending

Bending loads are superimposed onto the axial load distribution as a local effect. The bending load formulation is included in all axial load cases. Bending “force” is a convenient representation for design. Bending stress is a function of the local radius of curvature in the string component.

Stress at the pipe’s outer diameter due to bending can be expressed as:

Where:

σbending = stress at the pipe’s outer surface

E = elastic modulus

D = nominal outside diameter r = radius of curvature

Expressed as a force in English units, this can be simplified to: F_bending = 7.272 x 10-6EDφA_s

Where:

F_bending = bending force, lb φ = dogleg severity (o_{/100 ft)}

D = nominal outside diameter, inches A_s = cross-sectional area, in2

E = Young’s Modulus, lb/in2

For steel pipe where E = 30 x 10-6 lb/in2, then:

F_bending = 2186DφA_s

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Triaxial Stress Analysis

Triaxial stress is not a true stress. It is a way of comparing a generalized three-dimensional stress state to an uniaxial failure criteria (the yield strength). The triaxial stress is often called the von Mises equivalent (VME) stress.

If the triaxial stress exceeds the yield strength, a yield failure is indicated. The triaxial safety factor is the ratio of the material’s yield strength to the triaxial stress.

Von Mises Equation

Where:

Y_p = minimum yield strength of the pipe, lb/in2 σVME = triaxial stress

σz = axial stress

σθ = tangential or hoop stress σr = radial stress

Y

_p

_≥

_σ

_VME

1

2 ---

[

(

σ

_z

–

σ

_Θ

)

2

+

(

σ

_Θ

–

σ

_r

)

2

+

(

σ

_r

–

σ

_z

)

2

]

1 2⁄

=

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Triaxial Design Ellipse

Plotting the loads on this ellipse allows a direct comparison of the triaxial criteria with the API ratings. Loads that fall within the design envelope meet the design criteria.

Combined compression and burst loading corresponds to the upper left quadrant of the design envelope. This region is where triaxial analysis is most critical because reliance on the uniaxial criteria alone would not predict several possible failures.

Region of more efficient design

Triaxial limit not applicable in Collapse region

Region of non-conservative uniaxial design

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Combined tension and burst loading corresponds to the upper right quadrant of the design envelope. This region is where reliance on the uniaxial criteria alone may result in a design which is more conservative than necessary.

For most pipes used in the oilfield, collapse is an instability failure independent of material yield. The triaxial criteria is based on elastic behavior and the yield strength of the material and hence, should not be used with collapse loads. The one exception is for thick wall pipes with a low D/t ratio, which have an API rating in the yield strength collapse region. This collapse criteria along with the effects of tension and internal pressure (which are triaxial effects) result in the API criteria being essentially identical to the triaxial method in the lower right quadrant of the triaxial ellipse for thick wall pipes.

For high compression and moderate collapse loads experienced in the lower left quadrant of the design envelope, the failure mode is

permanent corkscrewing due to helical buckling. It is appropriate to use the triaxial criteria in this case.

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Buckling

All service loads should be evaluated for changes in the axial load profile, triaxial stress, pipe movement, and the onset and degree of buckling. Buckling will occur if the buckling force, F_buckling, is greater than a threshold force, F_p, known as the Paslay buckling force.

Where:

F_a = actual axial force (tension positive)

p_i = internal pressure

p_o= external pressure

F

_p

=

4w

₍

sin

_Θ

_{) EI}

₍

_{( ) r}

_⁄

₎

Where:

w = distributed buoyed weight of casing θ = hole angle

EI = pipe bending stiffness r = radial annular clearance

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Casing Buckling in Oil Field Operations

Buckling should be avoided in drilling operations to minimize casing wear. Buckling can be reduced or eliminated by:

• Applying a pickup force after cementation before landing the casing • Holding pressure while WOC (Wait-on-Cement) to pre-tension the

string (subsea wells) • Raising the top of cement • Using centralizers

• Increasing pipe stiffness

In production operations, casing buckling is not normally a critical design issue. However, a large amount of buckling can occur due to increased production temperatures in some wells. A check should be made to ensure that plastic deformation or corkscrewing will not occur. This check is possible by using triaxial analysis and including the bending stress due to buckling.

In high temperature applications, the intermediate and surface casings should also be checked for possible buckling occurring.

Permanent corkscrewing will only occur if the triaxial stress exceeds the yield strength of the material.

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API Connection Ratings

Connection ratings for 8 round (STC and LTC) and buttress (BTC) casing connections are based on four failure criteria given in API Bulletin 5C3:

• Burst (Internal Yield) - The internal pressure which will initiate

yield at the root of the coupling based on connection geometry and yield strength.

• Leak - The internal pressure which exceeds the contact pressure

between the connection’s seal flanks.

• Fracture - The axial force which causes either the pin or coupling

to fracture based on the ultimate tensile strength. This is not consistent with the pipe body axial strength, which is based on yield strength.

• Jump Out - The axial force at which an 8 round pin “jumps” or

“pulls” out of the box without fracturing. This criteria only applies to STC and LTC connections.

The StressCheck software always reports the minimum safety factor based on pipe body or connection. If the connection is limiting the design, then the criteria with which the API connection fails will be presented.

This does not indicate that the connection is failing to meet the failure criteria, but purely that it is the limiting part on the tubular. An example of a string summary is shown below:

Production Casing Burst Collapse Axial Triaxial

9 5/8”, 47.00, N-80 STC 1.47 2.61 1.45J 1.48 9 5/8”, 53.50, N-80 LTC 1.77 1.68 2.13J 1.61 9 5/8”, 58.40, P-110 BTC 2.18L 1.28 5.03 1.80

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Preliminary Design

The largest opportunity for cost savings can be achieved during this stage of the well design. Preliminary design includes:

• Data gathering and interpretation

• Determination of shoe depths and number of casing strings • Selection of hole and casing sizes

• Mud weight and top of cement (TOC) design

Why Should You Do A Preliminary Design?

The Landmark® CasingSeat™ software can offer the drilling engineer a selection of optimal casing ODs and setting depths based on geological, lithological properties and various drilling operations conditions. • The design can be used as input data for detailed design (cannot yet

order casings).

• Maximum savings are achievable at this stage.

• Standard designs (received wisdom) can be challenged.

What Data is needed to perform a Preliminary Design? • Number of casing strings

• Pipe diameters • Hole sizes

• Shoe and hanger depths

• Cement tops and mud program

Minimum Casing Diameter

Driven by well operational requirements: • Required well configuration

• Reservoir description • Completion design • Tubing size

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Minimum Casing Shoe Setting Depth

• Isolate overlying unstable formations • Isolate overlying shallow hydrocarbons

• Isolate overlying lost circulation (‘thief’) zones • Isolate overlying fresh water horizons

• Prevent failure of formations by induced circulating pressures during drilling operations

• Prevent failure of formations by induced circulating pressures during well control when closing in and circulating out an influx

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Detailed Mechanical Design

Design loads represent the worst case loads that a particular casing string could experience during the life of a well.

Burst Loads

Drilling Loads

Displacement to Gas

This drilling load case models displacement of the drilling mud in the casing by gas. It applies only to burst design.

Pore Pressure Gas Gradient Limit load case by the fracture pressure at the shoe. Fracture pressure at the shoe.

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By default, the gas column extends from the shoe depth (above open hole TD) to the wellhead, but you can specify the depth of a gas/mud interface, where the mud column is on top of the gas column. This load case represents a shut-in condition following a large kick. It is

commonly used as a worst-case burst criterion for protective (intermediate) and surface casing. It is sometimes described as the “maximum anticipated surface pressure,” or MASP. Load and the load-case formulation is consistent with so-called “maximum load” casing design principles.

The internal pressure profile is based on a mud density, a gas gradient, and the pore pressure at the influx depth. It is normally constrained by the fracture pressure at the shoe above the open hole TD. If you do not want to limit the internal pressure to the fracture pressure at the shoe, deselect the Limit to Fracture Shoe check box in the Tabular > Design Parameters > Analysis Options tab.

Gas Kick Profile

This drilling load case creates an internal pressure profile that simulates the maximum pressures imposed on the current string while circulating a gas kick to the surface. This “limited kick” burst criterion is less conservative than the full Displacement to Gas load case. It applies only to burst design.

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normally constrained by the fracture pressure at the shoe above the open hole TD. If you do not want to limit the internal pressure to the fracture pressure at the shoe, deselect the Limit to Fracture at Shoe check box in the Tabular > Design Parameters > Analysis Options tab.

Fracture @Shoe w/ Gas Gradient Above

This drilling load case applies only to burst design and commonly used as a worst-case burst criterion for protective (intermediate) and surface casing. This drilling load case models a shut-in well, after taking a large kick, where the formation fracture pressure at the shoe depth for the string above the open hole interval from whence the kick evolves is exceeded, and the mud in the casing is completely displaced by gas. The internal pressure profile is based on a gas gradient and the fracture pressure at the shoe above the open hole TD. This load case is very similar to the Displacement to Gas load case, except that pressure at the shoe above the open hole TD is always controlled by the fracture pressure. The Displacement to Gas load case is normally only controlled by fracture pressure if the calculated pressure at the shoe above the open hole TD exceeds the fracture pressure.

Fracture @ Shoe w/ 1/3 BHP at Surface

This drilling load case applies only to burst design where drilling load case models a shut-in well, after taking a kick, where the formation fracture pressure at the shoe depth for the string above the open hole interval from whence the kick evolves is exceeded. The pressure at the surface is taken to be equal to 1/3 of the pore pressure at the open hole TD. This construct for burst design is based on observation in the Gulf of Mexico that pressures greater than 1/3 bottom hole pressure (BHP) are infrequently seen at the surface. The internal pressure profile for the load case is linear between the surface pressure and fracture @ shoe

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boundary conditions. This load case is less conservative than the Displacement to Gas and Fracture @ Shoe w/Gas Gradient Above load cases.

Lost Returns with Water

This drilling load case models a condition of partial or full loss of subsurface well control where, following a kick event and consequential loss of circulation at the shoe above the open hole TD, water is displaced down the casing-drillstring annulus in an attempt to avoid further deterioration of hydrostatic well control, to a condition of frac @ shoe and water to surface, by maintaining the highest-possible fluid level in the annulus. It applies only to burst design.

The internal pressure profile is determined from the fracture pressure at the shoe above the open hole TD, and water in the annulus.

Surface Protection (BOP)

This drilling load case is used as a criterion for the design of surface pressure control (BOP) equipment and the upper portion of the casing and applies only to burst design of casing strings (not available for liners). The Surface Protection (BOP) load case is based on full displacement to gas, with a surface boundary condition equal to the surface pressure that would result from fracture pressure at the shoe above the deepest open hole interval for which the current string is exposed to drilling loads and a seawater gradient back to surface (that is,

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to Gas while providing a more conservative design pressure at shallow depths than that which would obtain from the Gas Kick Profile load case. Casing designed using the Surface Protection (BOP) burst criterion would be expected to incur a ductile burst failure deep in the string before a shallow failure would occur. The internal pressure profile is computed from the fracture pressure at the shoe above the open hole TD, seawater density, and gas density (deriving from either gas gravity or gas gradient).

Pressure Test

This drilling load case generates an internal pressure profile based on mud density, applied pressure at the wellhead, and an option for specifying a plug depth other than the shoe depth for the current string. If an alternative plug depth is specified, the applied pressure is only seen above that depth. This load case applies only to burst design.

Green Cement Pressure Test

This drilling load case models an internal pressure test immediately after bumping the plug during a single-stage primary cementing. The cement, still acting as a fluid, does not yet serve as a constraint over the cemented interval against casing-string length changes due to the combination of piston and Poisson effects. This load case is available for both burst and axial design, and can be selected in both the Tabular > Burst Loads and Tabular > Axial Loads dialog boxes. To consider Green Cement Pressure Test as a load for axial design, the load case must be selected in the Tabular > Axial Loads > Select tab.

This load case formulation includes a particular external pressure profile that is used irrespective of the external pressure profile selected on the Select tab, and irrespective of whether or not the Single External

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Pressure Profile check box is marked in the Tabular > Design Parameters Analysis Options tab for the current string.

The values specified on the Tabular > Initial Conditions > Cementing and Landing tab are used to construct the external and internal pressure profiles that arise from fluid hydrostatics alone. The specified test pressure is applied down to the float collar depth (also specified on the Tabular > Initial Conditions > Cementing and Landing tab).

A Green Cement Pressure Test is often performed to save operational time and to prevent the formation of a micro-annulus caused by applying a high-test pressure after the cement has hardened. This load case can also be used to increase the cemented-and-landed hang-off tension of casing landed with mandrel-type hanger systems (for example, in subsea wellheads), where the application of a pickup load prior to setting of slips is not feasible. In such cases, the test pressure must be maintained until the cement has developed sufficient compressive and bond strength to resist relaxation of test-pressure–induced axial strains on test-pressure release.

Selecting this load case and specifying a test pressure generates the axial load distribution that develops, with the casing at the current-string shoe depth specified in the Casing Scheme spreadsheet, immediately after completing the cement job (top plug landed and cement still a fluid) and on applying a surface pressure.

Since the casing string is not yet constrained from movement over the cemented length by hardened cement, the piston force resulting from the test pressure acting on the top plug causes a significant increase in the axial load.

The following factors are considered:

• The specified test pressure, applied to the inside of the casing and acting on a cross-sectional area corresponding to the casing ID at the float collar depth, which is specified on the Tabular > Initial Conditions Cementing and Landing tab of the Initial Conditions dialog box.

• The buoyed weight of the casing, based on the mud at shoe value specified for the current string on the Casing Scheme spreadsheet, and the displacement and cement slurry densities specified on the Tabular > Initial Conditions > Cementing and Landing tab.

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• Wellbore inclination, which will only be considered if the Deviated check box is marked on the Wellbore > General > Options tab and a valid well trajectory is defined in the Wellpath Editor spreadsheet. • Any bending-related axial pseudo-loads due to dogleg severities

defined in the Wellpath Editor or Dogleg Severity Overrides spreadsheets. These loads are superimposed on the axial load distribution as a local effect using the formulation presented in the Running in Hole load case description.

Drill Ahead

This drilling load case captures temperature profile and updated internal mud density for various string types. This load case will represent mud weight up / mud weight down after casing landing for drilling a new hole section. This particular load is required for strings that are not fully cemented in order to quantify how much buckling would occur on the uncemented section (prevents casing wear). This case can be used for any string except the last string (exception is protective casing or liner). Selecting this load case to visualize internal pressure profile which is defined with the heaviest mud weight used to drill the next hole section while the drill string is inside the current casing string, plus an ECD (Equivalent Circulating Density) value.

Gas Over Mud Ratio

This drilling load case illustrates the ratio of well control gas to drilling mud. This is a burst load case that is enabled for all casing strings associated to a next open hole section. The Gas Over Mud Ratio load case allows a user to define the gas over mud interface based on a wellbore fluid column occupied by drilling fluid, expressed as a fraction of the greatest open-hole TVD, measured from RKB (Rotary Kelly Bushing) or the hanger depth, to which the string is exposed to drilling loads.

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The internal pressure profile is based on mud density, a gas gradient, fracture pressure at shoe, fracture pressure margin, gas over mud ratio, gas/mud interface depth and the pore pressure at the influx depth (the default influx depth is the TD of the deepest open hole section

associated to the string of interest). The gas property shall be defined based on gradient or gravity. This load case temperature profile (drilling temperature profile) is used as the basis for determining a temperature and pressure dependent gas compressibility factor using a modified Redlich-Kwong cubic equation of state, the internal pressure profile can (or may not be) contained by the deepest fracture at shoe of the current string or string associated to the current string.

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Production Loads

Tubing Leak

This production load case applies only to burst design and models a surface pressure applied to the top of the production annulus as a consequence of a tubing leak near the wellhead. The internal pressure profile is based on produced (reservoir) fluid gravity (gas), or gradient (gas/oil) and reservoir pressure data (that is, pore pressure at the perforation depth specified in the Production Data dialog box).

Above the production packer, for which the depth is specified in the Production Data dialog box, the internal pressure profile is based on a surface pressure equal to the reservoir pressure minus the produced fluid’s hydrostatic pressure (from wellhead to perforation depth) applied to a packer fluid density entered in the Production Data dialog box. From the production packer down to the perforation depth, the internal pressure profile corresponds to that which would develop for full displacement of this section to the produced fluid (that is, reservoir pressure minus the produced fluid hydrostatic pressure from packer to perforation depth). From the perforation depth down to the well TD, the internal pressure profile is based on reservoir pressure applied to the selected packer fluid density.

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Stimulation Surface Leak

This production load case applies only to burst design and models an injection pressure applied to the top of the production annulus as a consequence of a tubing leak near the wellhead during injection.

The internal pressure profile is based on produced (reservoir) fluid gravity (gas) or gradient (gas/oil) and injection pressure data.

Above the production packer, for which the depth is specified in the Production Data dialog box, the internal pressure profile is based on a wellhead injection pressure specified on the Tubular > Burst Loads > Edit tab. It is applied to a packer fluid density entered in the Production Data dialog box. Below the production packer, the internal pressure profile corresponds to that which would develop for the wellhead injection pressure and wellhead-to-shoe displacement to the injection fluid.

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Injection Down Casing

This production load case models the internal pressure profile resulting from an injection operation down the casing. Frictional pressure losses are ignored. It applies only to burst design.

Gas Migration

This production load case models the effect of a gas bubble migrating upward in the annulus between the production casing and the protective casing. The gas is constrained against expansion as it rises unless the fracture pressure at the shoe for the protective casing is exceeded, and the gas bubble pressure and volume remain unchanged with upward migration. This load case applies only for burst design, and is only available for strings of name-type “Protective” and type “Casing” or “Tieback”. This “gas bubble inversion” results in reservoir pressure at the wellhead and can occur in a subsea completion where the outer annuli are permanently sealed at the wellhead. Gas migration behind production casing is normally as a result of primary cementing failure.

Collapse Loads

Drilling Loads

Full/ Partial Evacuation

This load case should be considered if drilling with air or foam. It may also be considered for conductor or surface casing where shallow gas is encountered. This load case would represent all of the mud being

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displaced out of the wellbore (through the diverter) before the formation bridged off.

Lost Returns with Mud Drop

This drilling load case models evacuation of the casing due to lost circulation. It applies only to collapse design.

The internal pressure profile corresponds to a mud drop that can occur due to drilling below the shoe. This mud drop is calculated by assuming the hydrostatic column of mud in the hole equilibrates with a specified pore pressure at a specified depth.

The default depth corresponds to the depth with a pore pressure resulting in the lowest EMW in the open hole section. For prospects where there is uncertainty about the pore pressure profile, a seawater or normal pressure gradient is often used to calculate the mud drop depth.

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Cementing

The external pressure profile for this drilling load case is self-described, modeling the differential pressure due to the higher lead and tail cement slurry densities on the outside of the casing, from the top of cement (TOC) to the shoe, immediately after the cement is displaced. It is unaffected by external pressure profile selections made on the Tubular > Collapse Loads > Select tab. This load case applies only to collapse design.

If a displacement fluid is used that has a lesser density than the current-string value for Mud at Shoe in the Casing Scheme spreadsheet (for example,

seawater), the addition to collapse loading is considered both above and below the top of cement (TOC).

Drill Ahead

The Drill Ahead load case is explained earlier. (“Drill Ahead” on page 2-34)

Collapse Well Containment Screening Tool (WCST)

This load case should be considered to determine if a well can be contained via a capping stack in the event of a worst case discharge scenario. The capping stack helps in bringing a well under control in case of a blowout. It is essentially a lighter, specialized version of a blowout preventer that uses similar components to stop or control the flow of oil and gas. The Collapse (WCST) load case applies to collapse design and is specified in the Tabular > Collapse Loads > Select tab. Loads Collapse (WCST) option must be checked to obtain a permit to drill in the Gulf of Mexico deep-water scenarios.

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Production Loads

Full Evacuation

This production load case models total evacuation of the casing due to the complete loss of workover or packer fluid into the formation, a large drawdown of a low permeability or low pressure production zone, or gas lift operations. It applies only to collapse design.

The internal pressure profile corresponds to an air column whose density profile is calculated with a temperature-dependent and

pressure-dependent compressibility factor. Despite the similarity of this load case to the Full/Partial Evacuation drilling collapse load case, it is included to account for worst-case production temperature effects.

Above/Below Packer

This production load case represents a combination of internal pressure profiles above and below the packer that can occur during different operations. It applies only to collapse design.

Above the packer during production, it is assumed that the casing will never see the fully evacuated pressures that can occur below the packer because the production annulus is never in pressure communication with the open perforations. In this case, the internal pressure profile consists of a hydrostatic gradient due to the packer fluid density above the packer and a fully evacuated profile below.

However, during completion or workover operations where the

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This second scenario is modeled by specifying a reduced pressure at the perforations and enabling the fluid drop above packer.

This load case uses the worst-case collapse pressures from both scenarios (that is, a partial evacuation above the packer and full evacuation below) and represents a less severe alternative to a full evacuation.

Gas Migration

Unlike the burst version of this production load case, the collapse version uses a self-described external pressure profile regardless of which external pressure profile was specified on the Tabular > Collapse Loads > Select tab, and irrespective of whether or not the Single External Pressure Profile check box was marked. This load case applies only to collapse design. It is only enabled for strings whose Casing Scheme spreadsheet reads Production in the “Name” cell and either Casing or Tieback in the “Type” cell. An analogous load case applies to burst design.

This load case models a gas bubble migrating upward in the annulus behind the production casing. Since the bubble is not allowed to expand unless the fracture pressure at the previous casing's shoe is exceeded (that is, the pressure is not bled off at the wellhead), the bubble's pressure and volume do not change as it migrates upward.

This “gas bubble inversion” results in reservoir pressure at the wellhead and can occur in a subsea completion where the outer annuli are permanently sealed at the wellhead, allowing the operator no means to monitor or relieve pressure. Gas migration is normally caused by channels in the cement between the production casing and a permeable reservoir.

The internal pressure profile is based on the packer fluid density. The external pressure profile corresponds to the reservoir pressure applied at the casing hanger depth to the annulus fluid hydrostatic head, but limited to the fracture pressure at the prior shoe. If you do not want to limit the internal pressure to the fracture pressure at the shoe, you can disable the Limit to Fracture at the Shoe option.

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Axial Loads

Running and Cementing

Running in Hole - Avg. Speed

This axial load profile does not represent a load distribution seen by the pipe at one particular time. Instead, it is constructed by calculating the maximum tension seen at each point on the casing string while running the casing in the hole.

The maximum tension experienced by a joint of casing is normally the tension when picking up out of the slips immediately after making up the joint. The assigned axial pseudo-load arising from dogleg-induced bending stress can cause the maximum tension to occur at depths where local well curvature (dogleg severity) was defined in either the Survey Editor or Dogleg Severity Overrides spreadsheets. The following factors are considered:

• The buoyed weight of the casing, based on the Mud at Shoe value specified for the current string on the Wellbore > Casing and Tubing Scheme spreadsheet.

• The wellbore inclination if a valid well trajectory was defined in the Wellbore > Wellpath Editor spreadsheet.

• Any bending-related axial pseudo-loads due to dogleg severities defined in the Wellbore > Wellpath Editor or Wellbore > Dogleg Severity Overrides spreadsheets. These loads are superimposed on the axial load distribution as a local effect.

Overpull Force

Selecting this load case and specifying an overpull force generates an axial load profile that reflects this incremental force above the current hookload when running the casing string in the hole.

Like the Running in Hole load profile, this axial load profile does not represent a load distribution seen by the pipe at one particular time while running the pipe (that is, the overpull force is not just applied when the casing is on bottom). Instead, the case is considered at each stage of the