well plan

Part Number: 220027A - July 2008

WELLPLANTM Software Training ManualRelease 2003.16.1.7

Participant Guide

May 2008

Landmark Learning

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Landmark WELLPLANTM Software Version 2003.16.1.7 Training Manual

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Contents

Getting Started ................................................................................................................. iManual Overview ............................................................................................................... i

Data ........................................................................................................................ iIcons Used in Manual ............................................................................................ ii

Technical Support Information ........................................................................................... iii

Basics ................................................................................................................................... 1Overview............................................................................................................................. 1Exercise 1: Creating the Data Hierarchy ............................................................................ 2

Steps and Questions ..................................................................................................... 2Answers ....................................................................................................................... 4

Exercise 2: Specifying Tubular Properties, and Working With Catalogs .......................... 12Steps and Questions ..................................................................................................... 12Answers ....................................................................................................................... 14

Exercise 3: Using the Case Menu, Libraries, and Configuring the Workspace ................. 22Steps and Questions ..................................................................................................... 22

Using the Case Menu ............................................................................................. 22Using Libraries ...................................................................................................... 25Configuring the Workspace ................................................................................... 25Configuring and Using Plots .................................................................................. 27

Answers ....................................................................................................................... 30Using the Case Menu ............................................................................................. 30Using Libraries ...................................................................................................... 38Configuring the Workspace ................................................................................... 45Configuring and Using Plots .................................................................................. 55

Drilling .................................................................................................................................. 1Overview............................................................................................................................. 1

Data ........................................................................................................................ 1Workflow ............................................................................................................... 1Workflow Solution ................................................................................................ 2What Is Covered .................................................................................................... 2

Torque Drag Analysis (Using the Torque Drag Analysis Module) ............................. 5Input and Review Well Configuration and Analysis Options ............................... 5Analyze Results at TD ........................................................................................... 7Analyze Torque and Drag at Other Depths ........................................................... 9

Analyze Hydraulics (Using the Hydraulics Module) .................................................. 11Input and Review Well Configuration and Analysis Options ............................... 11

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Analyze Hole Cleaning .......................................................................................... 11Analyze Pressure Loss and Annular Velocity ....................................................... 13Determine Required Horsepower .......................................................................... 14Check ECD’s ......................................................................................................... 15Bit Optimization .................................................................................................... 16Final Design Check ............................................................................................... 17

Analyze Surge/Swab Pressures and ECDs (Using the Surge Module) ....................... 18Input and Review Well Configuration and Analysis Options ............................... 18Analyze Transient Responses ................................................................................ 18

Investigate Well Control (Using the Well Control Analysis Module) ........................ 21Input and Review Well Configuration and Analysis Options ............................... 21Determine Kick Type ............................................................................................ 21Estimate Influx Volume ......................................................................................... 21Analyze Kick Tolerance ........................................................................................ 22Use Animation to Review Results ......................................................................... 23Generate a Kill Sheet ............................................................................................. 23

Determine Critical Rotational Speeds (Using Critical Speed Module) ....................... 26Input Analysis Parameters ..................................................................................... 26Examine The Stresses Acting On The Workstring ................................................ 27Examine String Displacements .............................................................................. 28Review Bending Moments and Shear Stresses ...................................................... 28Review Results in 3D Plots ................................................................................... 29

Predict BHA Build and Drop (Using Bottom Hole Assembly Module) ..................... 30Input Analysis Parameters and Review Results .................................................... 30Determine Where BHA Contacts the Wellbore .................................................... 31Evaluate Effect of WOB and ROP ........................................................................ 32

Stuck Point Analysis (Using Stuck Pipe Module) ....................................................... 33Input General Analysis Parameters ....................................................................... 33Determine the Stuck Point ..................................................................................... 33Setting and Tripping the Jar ................................................................................... 34Yielding the Pipe ................................................................................................... 34Backing Off ........................................................................................................... 35

Drilling Solution .............................................................................................................. 1Overview ............................................................................................................................ 1

Torque Drag Analysis (Using the Torque Drag Analysis Module) ............................. 2Input and Review Well Configuration and Analysis Options ............................... 2Analyze Results at TD ........................................................................................... 10Analyze Torque and Drag at Other Depths ........................................................... 20

Analyze Hydraulics (Using the Hydraulics Module) .................................................. 25Input and Review Well Configuration and Analysis Options ............................... 25Analyze Hole Cleaning .......................................................................................... 26Analyze Pressure Loss and Annular Velocity ....................................................... 30Determine Required Horsepower .......................................................................... 35Check ECD’s ......................................................................................................... 38



Bit Optimization .................................................................................................... 40Final Design Check ................................................................................................ 43

Analyze Surge/Swab Pressures and ECDs (Using the Surge Module) ....................... 45Input and Review Well Configuration and Analysis Options ............................... 45Analyze Transient Responses ................................................................................ 45Tripping In Operation ............................................................................................ 48

Investigate Well Control (Using the Well Control Analysis Module) ........................ 50Input and Review Well Configuration and Analysis Options ............................... 50Determine Kick Type ............................................................................................. 51Estimate Influx Volume ......................................................................................... 52Analyze Kick Tolerance ........................................................................................ 53Use Animation to Review Results ......................................................................... 61Generate a Kill Sheet ............................................................................................. 62

Determine Critical Rotational Speeds (Using Critical Speed Module) ....................... 68Input Analysis Parameters ..................................................................................... 68Examine The Stresses Acting On The Workstring ................................................ 69Examine String Displacements .............................................................................. 74Review Bending Moments and Shear Stresses ...................................................... 76Reviewing Results in 3D Plots .............................................................................. 77

Predict BHA Build and Drop (Using Bottom Hole Assembly Module) ..................... 78Input Analysis Parameters and Review Results .................................................... 78Determine Where BHA Contacts the Wellbore ..................................................... 80Evaluate Effect of WOB and ROP ........................................................................ 81

Using Stuck Point Analysis (Using Stuck Pipe Module) ............................................ 83Input General Analysis Parameters ........................................................................ 83Determine the Stuck Point ..................................................................................... 83Setting and Tripping the Jar ................................................................................... 84Yielding the Pipe ................................................................................................... 85Backing Off ............................................................................................................ 85

Running Liner ................................................................................................................... 1Overview............................................................................................................................. 1


Input and Review Well Configuration and Analysis Options ..................................... 3Centralizer Placement (Using OptiCem Module) ........................................................ 3

Using Bow Centralizers ......................................................................................... 3Using Rigid Centralizers ........................................................................................ 4

In-Depth Torque Drag Analysis (Using Torque Drag Module) .................................. 5Matching Friction Factors to Actual Field Data .................................................... 6

Determining Surge and Swab Pressures (Using Surge Module) ................................. 7Input and Review Well Configuration and Analysis Options ............................... 7Specify the Operation Data .................................................................................... 7



Analyze Transient Response ................................................................................. 8Check the Tripping Schedule ................................................................................ 8Reciprocating ......................................................................................................... 9

Condition the Well Prior to Cementing (Using Hydraulics Module) .......................... 10

Running Liner Solution............................................................................................... 1Overview ............................................................................................................................ 1

Input and Review Well Configuration and Analysis Options ..................................... 2Centralizer Placement (Using OptiCem Module) ....................................................... 3

Using Bow Centralizers ......................................................................................... 3Using Rigid Centralizers ....................................................................................... 6

In-Depth Torque Drag Analysis (Using Torque Drag Module) .................................. 8Matching Friction Factors to Actual Field Data .................................................... 12

Determining Surge and Swab Pressures (Using Surge Module) ................................. 15Input and Review Well Configuration and Analysis Options ............................... 15Specify the Operation Data .................................................................................... 16Analyze Transient Response ................................................................................. 17Check the Tripping Schedule ................................................................................ 22Reciprocating ......................................................................................................... 25

Condition the Well Prior to Cementing (Using Hydraulics Module) .......................... 28

Cementing the Liner ..................................................................................................... 1Overview ............................................................................................................................ 1


Open the Case .............................................................................................................. 4Input and Review Wellbore Data ................................................................................ 4

Review Hole Section, String, and Wellpath Data ................................................. 4Define Cement Slurries and Spacers ..................................................................... 5Review Pore Pressure and Fracture Gradient Data ............................................... 5Review or Input Geothermal Gradient Data .......................................................... 5Review or Input Circulating System Data ............................................................. 5

Centralizer Placement .................................................................................................. 6Specify Depths of Interest ..................................................................................... 6

Estimate Bottom Hole Circulating Temperature ......................................................... 6Input Cement Job Data ................................................................................................ 7Analyze Results ........................................................................................................... 9

Review Circulating Pressures ................................................................................ 9Review Downhole Pressure Profiles ..................................................................... 9Review Density and Hydrostatic Profiles .............................................................. 10Compare Rates In and Out ..................................................................................... 10Review Wellhead and Surface Pressures ............................................................... 10



Review Hookloads ................................................................................................. 10Use the Fluid Animation to Analyze Job Parameters ............................................ 11Review Hole Cleaning .......................................................................................... 11Fine-Tune the Job .................................................................................................. 12

Cementing the Liner Solution ................................................................................. 1Overview............................................................................................................................. 1

Open the Case .............................................................................................................. 2Input and Review Wellbore Data ................................................................................. 4

Review Hole Section, String, and Wellpath Data .................................................. 4Define Cement Slurries and Spacers ..................................................................... 7Review Pore Pressure and Fracture Gradient Data ................................................ 8Review or Input Geothermal Gradient Data .......................................................... 9Review or Input Circulating System Data ............................................................. 10

Centralizer Placement .................................................................................................. 10Specify Depths of Interest ...................................................................................... 10

Estimate Bottom Hole Circulating Temperature ......................................................... 11Input Cement Job Data ................................................................................................ 12Analyze Results ........................................................................................................... 16

Review Circulating Pressures ................................................................................ 16Review Downhole Pressure Profiles ...................................................................... 17Review Density and Hydrostatic Profiles .............................................................. 17Compare Rates In and Out ..................................................................................... 18Review Wellhead and Surface Pressures ............................................................... 19Review Hookloads ................................................................................................. 20Use the Fluid Animation to Analyze Job Parameters ............................................ 21Review Hole Cleaning ........................................................................................... 24Fine-Tune the Job .................................................................................................. 26

Landmark Learning May 2008 i

Getting Started

Manual Overview

This manual contains one chapter covering basic functionality. The remaining chapters cover three workflows: Drilling, Running Liner, and Cementing. Each workflow is covered in two chapters. One chapter contains the exercise or workflow steps, and the other chapter contains the workflow solution. If the exercise steps do not provide enough information to complete the step, please refer to the solution in the subsequent chapter.

An overview of each workflow is contained in the exercise section pertaining to the workflow.

Data

The data used in this exercise is not from an actual well. Although an attempt has been made to use realistic data in the exercise, the intent when creating the data set is to display as much software functionality as possible. Therefore, some data may not be realistic. Please do not let the accuracy of the data overshadow learning software functionality.

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Icons Used in Manual

The Concepts icon indicates sections where conceptual information related to the software are detailed.

The Tip section has some key information to increase your efficiency using the application.

The Observe icon draws you attention to a particular section of a dialog, view, plot, or other portion of the software.

The Caution icon indicates critical information that will impact results.

iii May 2008 Landmark Learning


Technical Support Information

Landmark operates a number of Technical Assistance Centers (TACs). Additional support is provided through district support offices around the world. If problems cannot be resolved at the district level, Landmark's escalation team is called to resolve your incidents quickly.

Support information is always available on the Landmark Graphics Support internet page.

http://css.lgc.com/CustomerSupport/CustomerSupportHome.jsp

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Landmark Learning May 2008 1-1

ChapterBasics

Overview

Exercise 1: Creating the Data Hierarchy

In this exercise you will create a new company, project, site, well, wellbore, design, and case.

Exercise 2: Specifying Tubular Properties and Working With Catalogs

In this exercise, you will create a new pipe grade and then use this pipe grade to create a new pipe in an inventory you create. You will also review creating a unit system and importing a catalog.

Exercise 3: Using the Case Menu, Libraries, and Configuring the Workspace

This exercise builds on the previous two exercises. Using the data hierarchy created in Exercise 1, you will specify additional data that defines the case you are analyzing. You will use the information you entered into the catalog in Exercise 2 as well as use the catalog you imported. This exercise will also familiarize you with using libraries to quickly use pre-defined strings or fluids. You will also learn how to configure the workspace (tabs) for easily accessing the data and results you need.

1

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Exercise 1: Creating the Data Hierarchy

Steps and Questions

1. Launch WELLPLAN.

2. Enter your User ID and Password on the login screen.

3. Create a new company.

4. Specify Company properties.

a) Rename the company Class. Entry of other company information is not required for this course at this time.

b) What would you do if you want to prevent editing of the company level data?

c) How do you prevent editing of all data associated with the company?

5. Create a new project.

a) Name the project Class Project. Use Mean Seal Level as the System Datum. Entry of other project information is not required for this course at this time.

6. Create a new site.

a) Specify general site information. Name the site Class Site. The Default Site Elevation is 100 feet above MSL. Use Grid as the North Reference. Do not apply a tight group. (Use Unrestricted.) Entry of other site information is not required for this course at this time.

7. Create a new well.

a) Specify general well information. Name the well Class Well. Do not use a Tight Group. Use API Well Units. Leave other fields on this tab blank.

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b) What unit system will be used for any Design or Case associated with this Well? (Hint: Use the online help.)

c) Specify the well depth reference, configuration (offshore or onshore), and to view a depiction of the datum. This is an subsea well in 500 ft of water. Specify a 490 ft wellhead elevation.

d) What datum will be used for Designs associated with this well? (Hint: Use the online help.)

e) Entry of other well information is not required for this course at this time.

8. Create a new wellbore.

a) Define general information about the wellbore. Name the wellbore Class Wellbore. Entry of other wellbore information is not required for this course at this time.

9. Create a prototype design for wellbore Class Wellbore. Name the design Class Design.

10. Create a case for design Class Design. Name the case Class Case.

11. Open the case you created.



Answers

1. Launch WELLPLAN using Start > Programs > Landmark Engineer’s Desktop > WELLPLAN.

2. Enter EDM as the User ID and landmark as the Password on the login screen.

3. Create a new company. Using the Well Explorer, right-click on the database canister and select New Company from the menu.



4. Specify Company properties.

a) Using the Company Properties > General tab, rename the company Class.

b) To prevent editing of the company level data, you can set a Company Level password by clicking the Company Level password box and specifying a password. You can also check the Company is Locked box, however this box will not be password protected unless you set a company level password.

c) To prevent editing of all data associated with the company (projects, sites, wells, wellbores, designs, and cases), click the Locked Data box to specify a locked data password.



5. Create a new project when prompted or by using File > New > Project.

a) Use the Project Properties > General tab to specify project properties. Name the project Class Project. Use Mean Seal Level as the System Datum.

6. Create a new site when prompted by clicking the Yes button.

a) Use the Site Properties > General tab to specify general site information. Name the site Class Site. The Default Site Elevation is 100 feet above MSL. Use Grid as the North Reference. Do not apply a tight group. (Use Unrestricted.)



7. Create a new well when prompted by clicking the Yes button.

a) Use the Well Properties > General tab to specify general well information. Name the well Class Well. Do not use a Tight Group. Use API Well Units. Leave other fields on this tab blank.

b) API units will be used for any Design or Case associated with this Well.



c) Use the Well Properties > Depth Reference tab to specify the well depth reference, configuration (offshore or onshore), and to view a depiction of the datum. This is an subsea well in 500 ft of water. Specify a 490 ft wellhead elevation.

d) Designs and Cases associated with this well will use the Datum with the Default box checked.



8. Create a new wellbore when prompted.

a) Use the Wellbore Properties > General tab to define general information about the wellbore. Name the wellbore Class Wellbore.



9. Create a design for wellbore Class Wellbore when prompted. Name the design Class Design. Indicate the design is a Prototype using the Phase drop-down list.

10. Create a case for design Class Design when prompted. Name the case Class Case.



11. If the case does not automatically open, you can open the case by double-clicking on the case name in the Well Explorer.



Exercise 2: Specifying Tubular Properties, and Working With Catalogs

Steps and Questions

1. Access the Materials spreadsheet.

2. Create a material named Class Material. This material has the following properties:

• Description: Leave blank

• Young’s Modulus: 30,000,000 psi

• Poison’s Ratio: 0.3

• Density: 490 lbm/ft3

• Temperature Deration: Steel

• Expansion Coefficient: 6.9 E -06 oF

• Anistropic Radial Yield (%): 100

• Anistropic Hoop Yield (%): 100

3. Access the Grades Spreadsheet.

4. Create a pipe grade named Class Grade. This grade has the following properties:

• Section Type: Casing/Tubing

• Material: Class Material

• Minimum Yield Strength: 125 kpsi

• Fatigue Endurance Limit: 25,000 psi

• UTS: 135 kpsi



5. Create a new Casing/Tubing Catalog. Name the catalog Class Casing.

6. Open the catalog you created and create a casing with the following properties. If a property is not listed below, leave the entry for that property blank.

• Nominal Diameter: 11 3/4”• Nominal Weight: 65 lbs• Grade: VMHCQ-125• Body OD: 11.75”• Body ID: 10.682 in• Weight: 65 lbs.• Pipe Type: Special• Drift ID: 10.625 in• Burst: 9,940 psi• Collapse: 6,540 psi• Body Yield Strength: 2,352,010 lbf• Linear Capacity: 0.1108 bbl/ft• Closed End Displacement: 0.1341 bbl/ft• Average Joint Length: 40.0 ft• Wall Thickness: 87.5%

a) If the Pipe Type is Standard, what casing properties cannot be specified?

b) Save and close the catalog.

7. Make a new Units set and name it ‘Class Units’. (Tools > Unit System) Base the new unit set on API units.

a) Use the unit ‘psi/ft’ for Mud Weight.

b) What is the active unit system?

c) Is the unit for density psi/ft? You can refer to Case > Fluid Editor and determine what unit is associated with density.

d) Activate the API unit set.

e) Have the units for mud density changed to ppg?

8. Save the case, but do not close it.



Answers

1. Access the Materials spreadsheet by double-clicking on Materials in the Well Explorer. You may need to expand the Tubular Properties node.

2. To create a material named Class Material, add the new material in the first blank line at the end of the list.

3. Access the Grades spreadsheet by double-clicking on Grades in the Well Explorer.

4. Create a pipe grade named Class Grade. Add the new grade in the first blank line at the end of the list. It is very important to specify the Section Type. If not, the grade will not be available to you when you create a new pipe in a catalog later in this exercise.



5. Using the Well Explorer, right-click on the Casing/Tubing catalog and select New from the right-click menu.

To create a new catalog:

1. Click on the catalog group (Drilling Tools, Completion Tools, or Wellhead Equipment) in the Well Explorer. For this example, select Drilling Tools.

2. Highlight the catalog type in the Well Explorer. In this example, Casing/Tubing is highlighted.

3. Right-click on the highlighted catalog category and select New from the right-click menu.

4. Specify the name of the new catalog in the Catalog Properties dialog.

5. Optional: Specify a description of the catalog to help you identify it later.

6. Click the Ok button and the catalog will be created.



6. Using the Well Explorer, double-click on the catalog you created to open it. After the catalog is opened, you can specify the new catalog entry.

a) If the Pipe Type is Standard, the Internal Yield Pressure, Collapse Resistance, and Body Yield Strength will be calculated based on the grade and associated material of the casing.

b) Save and close the catalog using the catalog node right-click menu.

7. The new catalog will be displayed in the Well Explorer within the catalog type you selected in Step 2.



7. Use Tools > Unit System. Base the new unit set on API units. Notice that the active Unit Set name is displayed in the Status Bar.

Click the New button to create a new unit system.

Select API from the Template drop-down list to base the new unit set on API units.



a) Use the unit ‘psi/ft’ for Mud Weight.

b) The active unit system is Class Units. You can tell what unit system is active by referring to the Active Viewing Unit System drop-down list on the Unit Systems Editor. The active unit system is also displayed in the Status Bar.

Select Mud Weight from the list of unit types and then select the unit you want to use for that unit type.



c) Refer to Case > Fluid Editor and determine what unit is associated with density.



d) Activate the API unit system using Tools > Unit System. Select API using the Active Viewing Unit System drop-down list.



e) Refer back to the Case > Fluid Editor and note the units are now ppg.

8. Save the case using File > Save As, or File > Save.



Exercise 3: Using the Case Menu, Libraries, and Configuring the Workspace

Steps and Questions

Using the Case Menu

1. Define the hole section, including the last casing, liner, and the open hole section. (Case > Hole Section Editor)

• The hole section depth is 17,968 ft.

• Use 12,534 ft of API 13 5/8”, 88.2 lb/ft, Q-125 casing with 17.5” effective hole diameter. (Effective hole diameter is only used in the OptiCem module for cementing analysis.)

• Enter 3,597 ft of 11 3/4”, 65 ppf, “Class Grade” liner. (“Class Grade” is the grade of the pipe. You must select this casing from the catalog you created in the last exercise.) Use Casing as the section type for liners. The effective hole diameter is 14.75”.

• There is 1,837 ft of 12 1/4” open hole. The open hole is gauge.

• Use .2 friction factor in cased hole and .3 in open hole.

2. Define a simple drill string to become familiar with using the Case > String Editor.

• String Depth: 17,968 ft

• Drill Pipe: API Drill Pipe Catalog, 17,045 ft, DP 5 in, 19.50 ppf, G, NC50(XH), P

• Heavy Weight: System Heavy Weight Catalog, 60 ft, HW Grant Prideco, 5 in, 49.7 ppf

• Jar: System Jar Catalog, 33 ft, Dailey Mechanical 6 1/4” OD, 2.25” ID)



• Heavy Weight: System Heavy Weight Catalog, 300 ft, HW Grant Prideco, 5 in, 49.7 ppf

• Drill Collar: API Drill Collar Catalog, DC, 390 ft, 8” X 2.5”, 7 H-90

• Stabilizer: System Stabilizer Catalog, 5 ft, IBS, 10 5/8” FG, 8 X 2.5”

• Drill Collar: API Drill Collar Catalog, DC, 30 ft, 8” X 2.5”, 7 H-90


• Drill Collar (Non-mag): API Drill Collar Catalog, 31 ft, NDC 8” X 2.5”, 7 H-90


• MWD: System MWD Catalog, 30 ft, MWD 8, 8 x 2.5 in

• Mud Motor: System Mud Motor Catalog, 30 ft, BHM 8, 8 x 2.5 in

• Sub: System Sub Catalog, 3 ft, BS 6, 6 x 2 1/2 in

• Bit: Security DBS, 10.625, Tri-Cone Bit, XL20, 517X

3. Import a catalog containing a bi-center bit using the file Class Bits.cat.xml. Change the bit in the string to the bi-center bit in the catalog you imported.

4. Import the wellpath data using the file WP2003_16TrainingWellpath.TXT. Your instructor will tell you where the file is. The column order and units are: MD (ft), Inc (deg), and AZ (deg). (Note: It is important that you correctly specify column order and units.) Review the wellpath data using Case > Wellpath > Wellpath Editor.

5. Create a fluid using the following properties. Activate the fluid after you create it. In this example, PV and YP are specified. If you have access to Fann data, it can be specified instead of PV and YP. Use the following properties:



• Name: 15.1 ppg OBM

• Type: Non Spacer

• Base Type: Oil

• Base Fluid: Diesel

• Density: 15.1 ppg at 70 oF, and 14.7 psi

• PV: 24 cp at 70 oF

• YP: 12 Tau0 at 70 oF

• Rheological Model: Bingham Plastic

6. Copy all pore pressure and fracture pressure from the file WPPoreFrac.xls. Paste the pore pressure data into Case > Pore Pressure and the fracture gradient data into Case > Fracture Gradient.

a) How is the first row of the Case > Pore Pressure spreadsheet calculated?

b) Depth is always required for entry into either of these spreadsheets. Why is it necessary to specify either EMW or pressure for entry or copy into these spreadsheets?

7. Specify the geothermal gradient. The surface ambient temperature is 80 degree F, the mudline temperature is 40 degrees F, and the temperature at TD is 279.5 degrees F. What is the geothermal gradient?

8. Specify mud pump and other circulating system data.

a) The surface equipment rated working pressure is 6,000 psi, the surface pressure loss is 100 psi, and the surface equipment type is IADC.



b) Select the following two pumps from the catalog. Activate only the A1400PT pump.

Using Libraries

9. Export the string you created by clicking the Export button on the Case > String Editor. Name the string 10.625” BHA.

10. Export the fluid titled 15.1 ppg OBM by clicking the Library button on the Case > Fluid Editor. You could change the name if you wished, but for this exercise we will not change the name.

11. Create a new case by right-clicking on the Database icon in the Well Explorer and selecting Instant Case from the right-click menu. Include this case in the Class company. Create new names for the remaining hierarchical levels. The well is subsea, in 328 ft of water, with a wellhead depth of 323 ft, and a default site elevation of 100 ft.

12. Open the case you created in the previous step if it is not already opened.

13. Open the Case > String Editor. Notice there is no string data in the String Editor. Import the 10.625” BHA string you created from the library. Set string depth to 17,950 ft.

14. Open the Case > Fluid Editor. Notice there is no fluid data in the Fluid Editor. Import the 15.1 ppg OBM fluid you created from the library.

15. Assume you want to transfer your libraries to another computer, or you want to share your libraries with another person. Create a library transfer file.

Configuring the Workspace

16. Continue to use the case you created in step 11. (Using the Instant Case option.)

Make Description Type Liner ID Rod OD Efficiency

Oilwell A1400PT Triplex 5” none 100

Oilwell A1700PT Triplex 6.5” none 100



17. Create the following tabs by renaming or creating additional tabs. Use window splitters near the scrollbars to create window panes.

a) Create a tab titled Schematic. On that tab, put the Well Schematic-Full String - not to scale.

b) Create a tab titled Editors. Create two horizontal panes on that tab. Open the Hole Section Editor in one pane and String Editor in the other pane.

c) Create a tab titled Wellpath. Open the Wellpath Editor in this tab.

d) Create a tab titled Plots. Open the Inclination plot in this tab.

18. To illustrate the Copy/Paste functionality between cases and designs, we will copy the hole section from the Class Case in the Class Project we worked with earlier in this exercise.

a) In the Well Explorer, highlight the case Class Case in the Class Project. What items are linked at the case level?

b) In the Associated Data Viewer (located at the bottom of the Well Explorer), right-click on the Hole Section entry and select Copy.

c) In the Well Explorer, right-click on the case you created in step 11 and select Paste from the right-click menu.

d) Notice the Associated Data Viewer indicates the hole section depth has changed.

e) Notice the Case > Hole Section Editor displays the hole section data.

19. Copy the wellpath from the design Class Design in the Class Project project to the design you created in step 11. Notice the wellpath is now displayed on the Wellpath tab and the inclination is displayed on the Plots tab.

20. Using the Associated Data Viewer, determine what data is linked at various hierarchy levels (design, case, wellbore, etc.).

a) what data is shown to be linked at the design level?

b) What data is shown to be linked at the case level?



c) What data is shown to be linked at the wellbore level?

21. Save the tab configuration as a User Defined Workspace. Name the workspace Class Workspace. Notice the workspace you created is now listed as a User Defined Workspace in the Well Explorer.

22. Save and close the case.

23. Reopen the case. What tabs are displayed and why?

24. You can export your workspaces if you want to share them with another person. Export the Class Workspace workspace you created.

25. In the Well Explorer, notice the node titled System Workspaces. System Workspaces are installed with the software. Can you modify a System Workspace? Review the tab configurations associated with each System Workspace.

26. Module Workspaces are a convenient way to use the same tab configuration every time you use an analysis module regardless of the case you are analyzing. To illustrate, continue to use the case you created in step 11.

a) Activate the Torque Drag Analysis module.

b) Apply the Torque Drag Analysis System Workspace. Did the tabs change?

c) Save this as the default workspace for all Torque Drag analysis.

d) Open the case Class Case in the project Class Project to open the case if it isn’t already opened.

e) Activate the Torque Drag Analysis module and notice the tab configuration. What tab configuration is used?

f) Assume you don’t want to use the Torque Drag default workspace configuration, how can you use the Class Workspace you created?

Configuring and Using Plots

27. This exercise step demonstrates the Freeze Line. Continue to use the case you created in step 11.



a) Freeze the curve on the Inclination plot using the Plots tab. Specify the color of the freeze line to be green, the width to 3, and change the name of the curve.

b) Using the Wellpath tab, change the inclination near 2500 ft to 50 deg. Notice the two curves visible at this depth on the Inclination plot.

c) Using the right mouse button, click on the curve with the 50 degree inclination. Select Hide Line. What happened to the line?

d) Add a Halliburton logo as a background logo to the plot. Your instructor can tell you the location of the file.

28. Generate a survey Vertical Section plot. Use the Plot tab.

a) Change the width of the data curve (vertical section line) on the Vertical Section plot to 3. (Hint: Right-click on the curve and use Line Properties option of the right-click menu.)

b) Activate the Graphics Toolbar by clicking anywhere on the plot.

c) Use the Data Reader (third button from left on Graphics Toolbar) to determine the vertical section at TD. What is it?

d) View X/Y coordinate data for the plot and then return to the plot view.

29. Click on the Properties button to open the Properties tabs. The following questions highlight the functionality of these tabs. (Hints: To easily view the changes to the plot, move the Properties tabs dialog box so that the plot is visible. Don’t forget to click the Apply button to implement changes.)

a) Using the Axis tab, Draw the X axis where Y = 0, and remove the tick marks from the Y axis.

b) Using the General/Grid tab, remove the grid lines from the plot.

c) Using the Labels tab, change the Y axis label to ‘True Vertical Depth’.

d) Using the Font tab, change the axis labels to green and italic.



e) Using the Markers tab, display data markers every 50 data points.

f) Using the Legend tab, turn off the legend.

g) Click OK and notice the changes to the plot.

30. Save and close this case.

31. Export this Case at the company level using the filename of your choice.



Answers

Using the Case Menu

1. Use Case > Hole Section Editor.

2. Use Case > String Editor.

3. Right-click on the Catalog node in the Well Explorer, and select Import Catalog from the right-click menu.Use the Import Catalog dialog to navigate to the correct folder, and to select the file you want to import. After you import the catalog, it will be



located under the catalog category titled Bits because it is a bit catalog.

1. Click on an inactive (gray) cell in the row defining the bit in the Case > String Editor.

2. Access String > Catalog using the Main Menu.

3. Select the catalog you imported by selecting Class Bits from the drop-down list.

4. Highlight the bit you want to use. (In this example, there is only one so it is automatically highlighted.)

5. Click OK and the selected bit will replace the bit in the Case > String Editor.



4. Use File > Import > Wellpath File to import the file WP2003_16TrainingWellpath.TXT. Review the wellpath data using Case > Wellpath > Wellpath Editor.

5. Enter mud properties on the Fluid Editor. Click the New button to enter data for a new fluid. (Case > Fluid Editor). After you are finished inputting fluid properties, click the Activate button to indicate you want this fluid used in the analysis.

6. Copy all pore pressure and fracture pressure from the file WPPoreFrac.xls. Use CTRL-C and CTRL-V to copy and paste the data. In Excel, select the columns you want to copy and use CTRL-C. In WELLPLAN, highlight the second row (because it is the first

It is important that you correctly specify column order and units.

Click the New button to enter a new fluid.

After you activate the fluid, a tear-drop symbol is placed next to the active fluid. There can only be one active fluid.



empty row in the spreadsheet) and use CTRL-V to paste the data. Paste the pore pressure data into Case > Pore Pressure and the fracture gradient data into Case > Fracture Gradient. Because these spreadsheets contain no data except for the first calculated row of data, you can either Overwrite or Append the data into these spreadsheets.

In Excel, select the columns you want to copy and use CTRL-C to copy the data to the clipboard.

Highlight the row where you want to begin the copy. In this example, highlight the first empty row. Click on the row number to highlight the row. Click CTRL V to paste the data into the spreadsheet.



a) The first row of this spreadsheet is automatically calculated from the data on the Well Properties > Depth Reference tab.

b) Entry of either EMW or pressure is required. The other value will be calculated.

7. Use Case > Geothermal Gradient. The Gradient is calculated based on the supplied temperature data.

Indicate whether you want to Overwrite existing data, or to Append data by clicking the appropriate button. In this example, either button will work.



8. Use Case > Circulating System.

a)



b)

Click the Add From Catalog button to select a mud pump from the catalog.

Double-click to select the Make, Description, Type, Liner ID, Rod OD, and Efficiency.

Use the System Pumps catalog.



Click on the Active box to check or uncheck it.

Check only the Oilwell HD1400-PT 5” Liner pump to make it the only active pump.



Using Libraries

9. Export the string you created by clicking the Export button on the Case > String Editor. Name the string 10.625” BHA.

10. Export the fluid you created by clicking the Library button on the Case > Fluid Editor. Highlight the fluid you want to move to the library. In this example, highlight the 15.1 ppg OBM. Click the left-facing arrow to copy the fluid to the library. The fluid will have the

Click the Export button to export the string to a library.

Click Yes to save the case before you add the string to the library.

Specify the name you want to give the string to have in the library. You will use this name to identify the string in the library.

Click the Export button to make a copy of the string in the library using the Assembly Name you provided.



same name in the library as it did in the Fluid Editor. You could change the name if you wished, but for this exercise we will not change the name.

Click the Library button to export a copy of a fluid to the fluid library.



Highlight the name of the fluid that you want to copy to the library. Click the left arrow to copy the fluid to the library.



11. Create a new case by right-clicking on the Database icon in the Well Explorer and selecting Instant Case from the right-click menu. Include this case in the Class company. Create new names for the remaining hierarchical levels. The well is subsea, in 328 ft

The fluid is now in the Library Fluids list.



of water, with a wellhead depth of 300 ft, and a default site elevation of 100 ft.

12. Double-click on the case name in the Well Explorer to open the case you created in the previous step if it is not already opened.

To include this case in the Class company, select Class from the Company drop-down list.

Notice the case you created is associated with the Class company.



13. Open the Case > String Editor. After the import, notice that the string data is displayed in the Case > String Editor.

Click the Import button. When the warning message appears, click Yes to indicate that you want to overwrite any existing string data.

Highlight the string library entry titled 10.625” BHA on the Import Assembly String From Library dialog. Click Import to import the string from the library.



14. Open the Case > Fluid Editor. Notice there is no fluid data in the Fluid Editor until after you import the fluid from the library. You must click the Activate button if you want to use the fluid in the analysis.

Click the Library button.

Highlight the fluid library entry titled 15.1 ppg OBM in the Library Fluids column.

Click the right arrow button to copy the fluid from the library to the wellbore fluids list. Click OK.



15. Using the Well Explorer, right-click on the Database Icon, and select Export from the right-click menu. Specify the filename you want to use and be sure that the Save as Type says Library Transfer Files (*.lib.xml). Click Save to create the library transfer file. You, or the person you are giving the file to, can import the library transfer file by selecting Import from the Database Icon right-click menu.

Configuring the Workspace

16. Continue to use the case you created in step 11. (Using the Instant Case option.)



17. Use View > Tabs.

Click New to create a new tab. Click Rename to rename an existing tab. Click Delete to delete the highlighted tab.

Window splitters

You can also rename a tab by double-clicking on the tab and specifying a new name.



a) Use View > Schematics > Well Schematic-Full String and then use the Option drop-down list to select Not To Scale.

b) On the tab titled Editors, put Case > Hole Section Editor in one pane and Case > String Editor in the other pane.



c) On the Wellpath tab, put the Case > Wellpath Editor.

d) On the tab titled Plots, open the View > Wellpath Plots > Inclination plot in this tab.



18.

a) In the Well Explorer, highlight the case Class Case in the Class Project.

b) In the Associated Data Viewer (located at the bottom of the Well Explorer), right-click on the Hole Section entry and select Copy.

Highlight the case by clicking on it. Refer to the Associated Data Viewer to determine which items are linked to the case. In this example, the Hole Section and Assembly use the default names of Hole Section and assembly. You can rename items in the Associated Data Viewer by highlighting them and then clicking on them again. The active fluid is also displayed.

To copy a hole section associated with the highlighted case, right-click on the hole section in the Associated Data Viewer. Select Copy from the right-click menu.



c) In the Well Explorer, right-click on the case you created in step 11 and select Paste from the right-click menu.

d)

Highlight the case you want to copy the hole section to. Right-click, and select Paste from the right-click menu.

Click Yes to indicate you want to copy.

Notice the Associated Data Viewer indicates the hole section depth has changed.



e)

19. Follow the same procedure as in the previous step.

20. Using the Well Explorer, highlight the hierarchy level you are interested in, and then view the linked data using the Associated Data Viewer.

a) Wellpath, pore pressure, fracture gradient, geothermal gradient, and casing designs are linked to the design level.

b) Rigs, hole section, assembly, and fluids are linked to the case level.

Highlight the design you are interested in. The Associated Data Viewer displays the items that are linked to this design.



c) Fluids are linked to the wellbore level.

21. In the Well Explorer, right-click on the User Defined Workspace and select New from the menu. Name the workspace Class Workspace and click OK. Notice the workspace you created is now listed as a User Defined Workspace in the Well Explorer.

22. Save and close the case by using the File menu, or by right-clicking on the case name in the Well Explorer.

23. Reopen the case by double-clicking on it in the Well Explorer. Notice that the tabs are those that you created. When you save a case, the current tab configuration is saved with the case data. Therefore, when you reopen the case, the tab configuration is automatically displayed.

24. Right-click on the workspace name and select Export.

25. System Workspaces are installed with the software and cannot be changed. You could use a System Workspace as the basis for a User Defined Workspace, but you must always save your workspaces as User Defined Workspaces. Review the tab configurations

Right-click on User Defined Workspace and select New from the right-click menu.

Notice the workspace you created is now listed as a User Defined Workspace in the Well Explorer.



associated with each System Workspace by double-clicking on the workspace name in the Well Explorer, or by highlighting the workspace and selecting Apply from the right-click menu.

26.

a) Activate the Torque Drag Analysis module by using Modules > Torque Drag > Normal.

b) Apply the Torque Drag Analysis System Workspace by double-clicking on it in the Well Explorer. Ignore any error messages that may be displayed in the Status Message area. These errors occur because we have not entered required analysis data.

Apply the workspace by highlighting the workspace and selecting Apply from the right-click menu.

Notice the tabs have changed.



c)

d) Using the Well Explorer, right-click on the case Class Case in the project Class Project to open the case if it isn’t already opened. If the case is open, you can use the Window menu to switch to this case.

e) Click on the toolbar button to activate the Torque Drag module. The tab configuration is the one you specified to use as the default for all Torque Drag Analysis, regardless of which case you are analyzing.

f) Double-click on the User Defined Workspace you created to apply that workspace. Notice the tab change.

Right-click on the Module Workspaces node in the Well Explorer tree and select Save As Default.

Notice that Torque Drag now appears beneath the Module Workspace node. This indicates that a workspace default has been associated to the Torque Drag Analysis module. (This isn’t the name of the workspace, but rather the name of the module.) You can only have one default for each analysis module, although you can change the default whenever you want.



Configuring and Using Plots

27.

a)

Using the Plot tab, place the cursor (arrow) on the data curve of the Inclination plot. Click the right mouse button, and select Freeze Line.

Specify the color of the freeze line to be green, the width to 3, and change the name of the curve.



b)

Using the Wellpath tab, change the inclination near 2500 ft to 50 deg.

Notice the two curves visible on the Inclination plot. The legend indicates the name of each curve.



c)

d) Add a background logo to the plot. Right-click anywhere on the plot and select Properties. Select the Background tab. Click the

Using the right mouse button, click on the desired curve. Select Hide Line.

When a line is hidden, it disappears from the plot.



Bitmap button. Add the Halliburton logo to the plot. Your instructor can tell you the location of the file.

Notice the logo is applied



28. Generate a survey Vertical Section plot using View > Wellpath Plots > Vertical Section.

a)

b) Activate the Graphics Toolbar by clicking anywhere on the plot.

Data Reader



c) Use the Data Reader (third button from left on Graphics Toolbar) to determine the vertical section at TD. What is it?

d) Click on the Grid View button (fourth button from the left on the Graphics Toolbar) to view X/Y coordinate data for the plot. Click the Arrow button (left button on Graphics Toolbar) to return to the plot view.

Move the data reader to the point on the curve that you are interested in. Read the coordinate values here.

To toggle between tabular data and plotted data, you can also select Graph/Grid from the right-click menu.



29. Click the toolbar button.

a) Using the Axis tab, Draw the X axis where Y = 0, and remove the tick marks from the Y axis.

b) Using the General/Grid tab, remove the grid lines from the plot.

Remove Tick Marks by unchecking the associated box.

Click this radio button to draw the x-axis where y=0.

Uncheck this box to remove the grid lines.



c) Using the Labels tab, change the Y axis label to ‘True Vertical Depth’.

d) Using the Font tab, change the axis labels to green and italic.

Specify the Y-axis label here.

Click the Axis Labels button to change the fonts used for axis labels.



e) Using the Markers tab, display data markers every 50 data points.

f) Using the Legend tab, turn off the legend.

Check the Show Data Markers box to indicate data point frequency.

Uncheck the Show Legend box to remove the legend from the plot.



g)

30. Right click on the case name in the Well Explorer and select Close.

31. Export this Case at the company level using the filename of your choice.

Click on the company containing the case you want to export. Select Export from the right-click menu.

Note: You must close all cases associated with the company before you can export.


ChapterDrilling

Overview

Data


Workflow

In this section we will drill one hole section in a well. During this analysis, we assume previous hole sections have been drilled, and will focus only on the current section being drilled.

The following is a brief, general overview of the workflow and does not include a description of all workflow steps.

Initial analysis evaluates the stresses acting on the string when the bit is at TD. Adjustments to the drill pipe are made based on this analysis. Next, the torque and drag is evaluated at depths other than TD.

After all string adjustments based on torque drag analysis are completed, hydraulics analysis begins. First of all, hole cleaning is reviewed. Flow rate adjustments are made to improve hole cleaning. Pressure losses, including system, string, and annulus are examined. Critical annular velocities are determined. Pump horsepower requirements are determined. ECDs are analyzed, and bit nozzle sizes are optimized. A final design check is performed to ensure hole cleaning, pressure losses, and ECDs are acceptable.

After the hydraulics analysis is completed, tripping surge and swab transient pressures are investigated.

2

WELLPLANTM Software Version 2003.16.1.7 Training Manual Chapter 2: Drilling


Well control analysis is the next step in the process. The kick type is determined, as well as the expected influx volume. Using the estimated influx volume, the kick tolerance is examined. A kill sheet is generated, and the well control animation is used to display the pressures and other parameters as the kick is circulated out of the wellbore.

After well control analysis is completed, critical vibrational speeds are investigated, as well as the stresses, bending moments, and displacements acting on the string.

Next, the BHA performance is investigated including the response of the BHA to various WOB and ROP combinations.

Finally, the forces required to set, trip, and reset a jar in the event the pipe becomes stuck are determined.

Workflow Solution

Solutions for the workflow steps in this chapter can be found in the Drilling Solution chapter.

What Is Covered

During this workflow you will:

Input General Well Data

• Integration between WELLPLANTM software modules

• Defining the hole section

• Defining the workstring and the component parameters

• Defining the wellpath and how to apply tortuosity

• Defining wellbore fluids

Torque Drag Analysis

• Understand the torque and drag analysis parameters, including:

• Analytical methods

• Stiff string and soft string models

Chapter 2: Drilling WELLPLANTM Software Version 2003.16.1.7 Training Manual


• Mechanical limitations

• Selecting desired tripping and drilling modes

• Defining friction factors

• Analyze torque drag at TD, and at other wellbore depths

• Examine effective and true tension and when to use each

• Examine fatigue

• Determine available overpull

• Determine the torque acting on the string

• Investigate the possibility of buckling

• Investigate ways to resolve torque and drag issues

Hydraulics Analysis

• Examine hole cleaning at various pump rates

• Investigate the effect of ROP on hole cleaning

• Determine pressure losses

• Determine annular velocity

• Input circulating system information

• Investigate required horsepower

• Check ECDs

• Optimize hydraulics

Surge Swab Analysis

• Analyze transient surge/swab pressures and ECDs

• Generate a trip schedule



Well Control Analysis

• Investigate well control

• Determine predicted kick type

• Estimate influx volume and kick tolerance

• Evaluate pressures as a kick is circulated out

• Predict a safe drilling depth

• Generate a kill sheet

Critical Speed Analysis

• Determine critical rotational speeds

• Examine the stresses acting on the workstring at various ROPs including the type of stress and where it occurs

• Examine string displacements

• Review bending moments

Bottom Hole Assembly Analysis

• Predict BHA build and drop

• Evaluate BHA contact points along the wellbore

• Analyze the effect of various WOB and ROP combinations on BHA performance

Stuck Pipe Analysis

• Estimate a stuck point for specified surface conditions, and string stretch

• Determine loads required to set and trip a jar

• Determine load required to yield the pipe



Torque Drag Analysis (Using the Torque Drag Analysis Module)

Input and Review Well Configuration and Analysis Options

1. Using the Well Explorer, open the Case titled Drilling.

2. Activate the Torque Drag Analysis module.

3. What is the mudline depth (MSL)?

4. Review the hole section information.

a. Why is the riser length 590 ft?

b. What friction factors are used?

5. Review the string information.

a. What is the string depth?

b. Does the drill pipe weight include the tool joint weight?

The Torque Drag Analysis module predicts the measured weights and torques while tripping in, tripping out, rotating on bottom, rotating off bottom, slide drilling, and backreaming. This information can be used to determine if the well can be drilled or to evaluate conditions while drilling a well. The module can be used for analyzing drillstrings, cas-ing strings, liners, tieback strings, tubing strings, and coiled tubing.

The Torque Drag Analysis module includes both soft string and stiff string models. The soft string model is based on Dawson’s cable model. In this model, the work string is treated as an extendible cable with zero bending stiffness. Friction is assumed to act in the direction opposing motion. The forces required to buckle the string are determined, and if buckling occurs, the mode of buckling (sinusoidal, transitional, helical, or lockup) is indicated. The stiff string model includes the increased side forces from stiff tubulars in curved hole, as well as the reduced side forces from pipe wall clearance.

The length of the top row component is automatically adjusted.



c. What type of connections are used for the drill pipe, and what is the make-up torque for the drill pipe connection?

6. Review the wellpath information.

a. What is the best azimuth to view the View > Wellpath Plots > Vertical Section plot?

b. How can you use this dialog to set the Vertical Section plot to use that azimuth?

7. Apply tortuosity to the open hole section. Use the Sine Wave Tortuosity Model, 12,500 ft MD Top, a 500 ft Angle Change Period, a 0.5 degree magnitude, and a 30 ft Depth Interval.

a. When should you use tortuosity?

b. When using the Sine Wave model, why should angle and pitch not be a multiple of each other?

c. Review the Inclination and Azimuth plots. What is causing the “corkscrews”?

8. What fluid is used in the analysis?

9. Specify the Torque Drag Analysis setup options. Check all the boxes in the Mechanical Limitations section. This information will now be displayed on the applicable plots.

In this example, only one MD Top is specified. Therefore, the same tortuosity will be applied to all data points below the specified MD Top.

Torque Drag Analysis uses viscosity and density for the analysis

The Soft String model is more widely used than the Stiff String model. For more information, refer to the online help.



10. Review the additional analysis parameters.

a. From what source are the friction factors coming from? (Calibrated, Hole Section Editor, etc.)

b. What operations will be analyzed?

c. What is the WOB (or overpull), and the bit torque?

Analyze Results at TD

11. Review the Summary Loads table.

a. What problems exist?

b. Can you determine where the problems occur?

c. What is the overpull margin with and without tortuosity applied? Continue the exercise with tortuosity applied.

d. If we consider viscous drag effects of the fluid acting on the drillstring, what is the overpull margin? What additional problem have we introduced and in what mode of operation?

e. Does buckling occur?

12. Review the Effective Tension plot.

a. Why not use the True Tension plot?

b. Which operation is close to exceeding the tension limit?

c. Is buckling predicted based on this plot?

13. Review the Torque Graph to determine the location in the string when the torque limit is exceeded for each operation that the Summary Loads table indicated.

14. Review the Fatigue plot to determine where fatigue may be a problem.

Using the Normal Analysis mode, we will review the results when the bit is at TD (total depth). Later we will use Drag Charts to review the results when the bit is at other depths along the wellpath.



a. What is fatigue, and why is it important? (Hint: Refer to the online help.)

b. What is one possible cause of the fatigue?

15. Review the load data to determine which limits are exceeded during the Backreaming, Rotating On Bottom, and Rotating Off Bottom operations. When backreaming, at what depth is the yield strength and utilization factor exceeded?

16. What can you do to avoid the problems in the string? There are several possible options. For this exercise, change the drill pipe.

a. One option would be to change the drill pipe to 5”, 25.6#, S, FH, Class 1 pipe.

b. Review the make-up torque and fatigue limits for this pipe.

17. Review the Normal Analysis Summary Loads table as another means to confirm the problems are resolved. Is the overpull over designed?

18. How could you save some money on the string? Continue to use the S grade pipe in the top 7,500 ft of drill pipe. Because the original drillpipe (5”, 19.5 lb/ft, G, NC50, P) was sufficient below that depth, change to the original pipe below 7,500 ft. Review results again using the Summary Loads table. (7,500 ft of S pipe is used because the problems began about 7,000 ft. The additional 500 ft allows for a margin of safety.)

There are other possible drill pipe configurations that would be acceptable. Because of time constraints, additional analysis will not be performed in the course setting at this time.

Analyze Torque and Drag at Other Depths

19. Select the Drag Charts analysis mode.

Using the Normal Analysis mode, we reviewed the results with the bit at TD (total depth). Now we will use Drag Charts to review the results when the bit is at other depths along the wellpath.



20. Analyze every 100 ft from 0 to TD.

21. Review the Hook Load chart.

a. What does the Max Weight Yield line represent?

b. How can you determine the overpull at a specific point?

22. Review the Torque Point chart.

a. This plot displays the torque at what depth?

b. Why is there 0 torque while tripping in and tripping out?

23. Specify an RPM of 80 for the tripping operations (as with a top drive). Notice the difference in the plot. Set the RPM back to zero before proceeding.

24. Review the Minimum WOB chart. Look at the last data point and compare the results to the Normal Analysis Summary table results. Notice the Run Depth is the same as the bit depth.

Much of the information on this dialog defaults from the data specified in the Normal Analysis mode.



Analyze Hydraulics (Using the Hydraulics Module)


25. Access the Hydraulics module.

26. Review the string information.

a. What are the bit nozzle sizes?

b. What are the flow rates and pressure losses for the mud motor?

c. What are the flow rates and pressure losses for the MWD?

Analyze Hole Cleaning

27. Access the Hole Cleaning - Operational analysis mode.

28. Review the analysis parameters.

29. Review the Hole Cleaning Operational plot at 600 gpm and a rate of penetration (ROP) of 50.

a. What is the minimum flow rate to clean the wellbore?

b. What is the bed height in the riser?

c. What is the bed height in the casing (between the drill pipe and the casing)?

The WELLPLANTM software Hydraulics module is designed to assist the engineer with the complicated issue of designing hydraulics. The module can be used to optimize bit hydraulics, determine the minimum flow rate for hole cleaning, determine the maximum flow rate to avoid turbulent flow, analyze hydraulics for surge and/or swab pressures and to quickly evaluate rig operational hydraulics.

The module provides several rheological models, including Bingham Plastic, Power Law, Newtonian, and Herschel Bulkley. The chosen rheological model provides the basis for the pressure loss calculations.



d. Will changing the flow rate help clean the annulus (not including the riser)? Try 615 gpm.

e. How much additional flow is needed to clean the riser? Try a flow rate of 720 gpm.

f. In order to pump at the lower flowrate of 615 gpm, add a booster pump. The injection depth is 590 ft, 40 degree F injection temperature, and an injection rate of 105 gpm.Now that you have added a booster pump, set the flowrate to 615 gpm. Are the wellbore and riser clean?

30. Review the Minimum flow Rate vs ROP plot.

a. At 0 RPM, what flowrate is required to achieve an ROP of 70 ft/hr?

b. How fast can you drill, and keep the wellbore clean, if you rotate at 30 rpm?

c. Set the rpm to 25 before proceeding.

Analyze Pressure Loss and Annular Velocity

31. Access the Pressure: Pump Rate Range analysis mode.

32. Review the surface equipment and mud pump information.

Use the slider on the plot to change the flowrate.

Using this plot, you can perform sensitivity analysis by selecting any RPM. To increase ROP, you can vary the RPM or the flowrate.

Rotary speed is the speed of the rotary bushing or the top drive.



a. What is the surface equipment rated working pressure?

b. What is the maximum discharge pressure and horsepower rating of the active pump?

33. Now that we know we need to pump at 615 gpm to clean the wellbore, analyze pressure losses for a range of flowrates to determine if our pumps can handle the required flow. Use the following analysis parameters:

• Analyze rates between 475 - 725 gpm using an increment of 50 gpm

• Include mud temperature effects

• Include tool joint pressure losses

• 9 hr circulation time

a. Where do the Maximum System Pressure and the Maximum Pump Power come from?

34. Review the pressure losses. Are the system pressures losses too high at 615 gpm?

35. Change from the 5660 psi pump to a 7500 psi pump.

36. Is there still a pressure loss problem?

37. Review the Annular Velocity plot .

a. Is there turbulent flow?

b. What is the minimum flowrate that causes turbulent flow?

c. If you want a turbulent flow regime in the open and cased hole, how fast would you need to pump? (Hint: Use the Annular Pump Rate plot.)

38. Save your data to the database.

To use the active pump in the analysis, you must update the Pumping Constraints on the Parameter > Rates dialog by clicking the Obtain from Circulating System button.



Determine Required Horsepower

39. Check the required horsepower using the Pressure: Pump Rate Fixed analysis mode. Pump at 615 gpm. .

a. What is the standpipe pressure? Is this less than the maximum pump pressure?

b. Using the pie-charts, review the power losses in the drillstring and annulus. What are the total power losses and how do they compare to the available power for the pump we have selected?

c. Using the pie-charts, review the pressure losses in the drillstring and annulus. What are the total pressure losses?

d. Activate the other 7500 psi pump, and use both in the analysis. (Both 7500 psi pumps should be active.) (Hint: This is a two step process. One step to activate the pump, and the other to use the pump in the analysis.)

e. Clear the status messages.

Check ECD’s

40. Continue using the Pressure: Pump Rate Fixed analysis mode to check the ECD’s.

a. Using the Pressure vs. Depth plot, is there likely to be trouble?

b. Does the ECD vs. Depth plot indicate any trouble?

c. Hide the pore and fracture pressure curves displayed on the ECD vs. Depth plot. .

d. Using the Freeze Line functionality, freeze the remaining curve on the plot. To identify the curve later, change the color and increase the thickness of the curve.

When using multiple pumps, the pump pressure used in the analysis is the minimum pump pressure for any active pump. However, if using multiple pumps, the HP used in the analysis is the combined HP of all active pumps.



e. Include cuttings loading in the analysis.

f. Refer back to the ECD vs Depth plot and notice the difference in the curves. Why is there a difference?

g. Review the Depth vs Pressure and ECD Chart. What does this chart tell you?

Bit Optimization

41. Access the Optimization Planning analysis mode, and specify the following analysis parameters. What size nozzles do we need to use to optimize based on Bit Impact Force or HHP?

• The minimum annular velocity is 120 ft/min.

• Allow 3 nozzles, with a minimum size of 14/32 nds

• Allow 100% bit flow

• Include tool joint pressure losses

42. Access the Pump Rate Fixed analysis mode.

43. Use the Rate dialog to investigate the effect on HSI when the nozzle sizes are changed.

a. What is the HSI?

b. Change the Local nozzles to three 15/32nds. What is the TFA?

c. Indicate that you do not want to use the String nozzles. What is the HSI now?

In order to include cuttings loading in the analysis, you must un-check the Mud Temperature Effects box. Then you can check the Include Cuttings Loading box.

Local nozzles can be used for sensitivity analysis so the String Editor nozzles can be left unchanged. After you finish the sensitivity analysis, you can copy the Local nozzles to the String Editor nozzles.



d. Notice the stand pipe pressure is close to the maximum pump pressure, so use three 16/32nd nozzles instead. What is the HSI now?

e. Copy these nozzles to the String Editor.

Final Design Check

44. Review the hole cleaning. Is everything ok?

45. Review the pressure losses. Is everything ok?

46. Review the ECD’s. Is everything ok?

Notice the Item Description field associated with the bit on the String Editor did not change when the Local Nozzles were copied to the String Editor. This field is for description only. You can change the description if you wish.



Analyze Surge/Swab Pressures and ECDs (Using the Surge Module)


47. Access the Surge module.

48. Review the pore pressures. At what measured depth is there a 0.5 ppg pore pressure increase in the open hole section (other than at the shoe)? (Hint: Use Convert Depth/EMW.)

Analyze Transient Responses

Tripping Out Operation

49. Specify operations data. Specify the following analysis parameters. Use defaults for other options.

• Swab analysis.

• Enter 15,000 ft for the Additional Depth of Interest.

The Surge module is a transient pressure model to determine surge and swab pressures throughout the wellbore caused by pipe movement. This analysis is used for well planning operations when surge pressures need to be controlled and to evaluate well problems related to pressure surges. It is also useful for critical well designs when other surge pres-sure calculation methods are not sufficiently accurate.

The Surge module is based on a fully dynamic analysis of fluid flow and pipe motion. This analysis solves the full balance of mass and bal-ance of momentum for pipe flow and annulus flow.

Surge solutions consider the compressibility of the fluids, the elasticity of the system, and the dynamic motions of pipes and fluids. Also con-sidered are surge pressures related to fluid column length below the moving pipe, compressibility of the formation, and axial elasticity of the moving string. In-hole fluid properties are adjusted to reflect the effects of pressure and temperature.



• Specify 12,500 (shoe), 15,000 (depth of interest), and 20,000 (TD) pipe depths. Use 270 ft/min for the pipe speed at all depths.

50. Review equivalent mud weight (EMW) vs Time. Examine all depths, but the following questions pertain to TD.

a. Why is the initial EMW presented on the plot not equal to the original mud weight?

b. Is there a problem?

c. How much of a swab effect exists (in ppg)?

51. Run a trip schedule for the open hole. What is the recommended safe trip speed?

52. Adjust the trip speed to 150 ft/min, and review the transient plots to confirm the problem is resolved.

Tripping In Operation

53. Change the operation from swab to surge. Leave all other parameters the same as for the swab operation.

54. Review the transient plot. Why was the analysis not performed?

55. Adjust the moving pipe depth, and review the transient response plot at all three moving pipe depths. Are there any problems?

56. Is it possible to experience a “swab” effect while tripping in and a “surge” effect while tripping out? Review any transient response plot.

For each depth of interest, the analysis will be performed assuming the pipe is at the depths specified in the Pipe Depth column using the trip speed specified in the Pipe Speed column.

The initial EMW is the downhole static mud weight. When you check the box to Include Mud Temperature Effects, the downhole static mud weight is adjusted based on mud type, fluid properties, and wellbore conditions.



Investigate Well Control (Using the Well Control Analysis Module)


57. Activate the Well Control Analysis module.

58. Review geothermal data.

59. Review well control setup data.

60. Review the temperature distribution model.

61. Review the geothermal plot.

Determine Kick Type

62. Specify the Kick Interval Gradient of 0.732 psi/ft. Why is this a kick while drilling? (Hint: Refer to the online help.)

Estimate Influx Volume

63. What type of kick detection method is used?

64. Review the reservoir information.

65. Review the reaction time.

The Well Control module can be used to

• Calculate the expected influx volume• Assist with casing design in terms of shoe settings depths• Calculate expected conditions resulting from an influx• Generate kill sheets• Determine maximum safe drilling depths and maximum allow-

able influx volumesWell Control Analysis analyzes three different influx types: oil, water, and gas. The default influx type is gas.If the influx type is gas, the analysis assumes the influx is a single, methane gas bubble. Dispersed gas influxes are not modeled. The influx density is the density of methane at the current temperature and pres-sure. The compressibility factor, Z, is based on the critical temperature and pressure of methane.



66. What is the expected influx volume, and how long did it take to detect the kick?

Analyze Kick Tolerance

67. Access the Kick Tolerance mode

68. Use the Wait and Weight method.

69. Specify the kick tolerance analysis parameters.

• The Kill Rate is 135 gpm.

• Specify the shoe depth as the Depth of Interest.

• Assume a 50 bbl kick

• Design for a 14.3 ppg kill mud (0.743 psi/ft)

• Analyze between the shoe and TD. (Depth Interval to Check is 7,500ft)

• Assume a Gas kick. This is the worst case kick type.

Available tabs on the Case > Well Control Setup dialog vary depending on selected analysis mode.

Click the F4 button to convert units.

The Depth Interval to Check begins at the Depth of Interest.

Influx types can be Gas, Oil, or Salt Water.



70. Analyze kick tolerance results.

a. What is the maximum allowable influx volume?

b. Is the annular pressure at the shoe between the pore and fracture pressures as the kick is circulated out?

c. What is the highest choke pressure?

d. Review the Maximum Pressure plot. How does this plot compare to the Pressure at Depth plot?

e. Review the Safe Drilling Depth plot. What does this plot tell you?

f. Review the Formation Breakdown Gradient plot. What does this plot tell you?

g. Will there be a problem if there is a full evacuation to gas?

Use Animation to Review Results

71. Use View > Animation > Schematic to view a representation of the fluids moving through the pipe and annulus using the Wait and Weight method. What fluid is in the wellbore and string at the end of the animation?

72. View the animation using the Driller’s method. What fluid is in the wellbore and string at the end of the animation?

73. Set the kill method back to Wait and Weight.

Generate a Kill Sheet

74. Access the Kill Sheet analysis mode.

75. Specify the following analysis parameters.

• Use a choke and kill line. (590 ft line length, and both choke and kill line IDs are 3.5 inches)

• Use the Wait and Weight method.

• BOP pressure rating is 10,000 psi.



• Casing burst pressure rating is 10,035 psi

• Casing burst safety factor is 80%

• Leak off pressure is 450 psi

• Leak off mud weight used for the leak off test is 13.8 ppg

76. Optional Step: Use the Notebook module to determine the formation breakdown pressure and equivalent mud gradient based on a leak off test. Use a test pressure of 450 psi.

a. What mud density should you use?

b. The leak off test was performed at the casing shoe. What is the casing shoe measured depth, and how can you easily determine the true vertical depth at the shoe?

c. How can you easily determine the air gap and sea depth?

d. How does the calculated equivalent mud gradient compare to the fracture gradient?

77. Access the Well Control Kill Sheet analysis mode.

78. Review the slow pump information.

79. Review the kill sheet analysis parameters. Specify a 6 bbl pit gain. Select the pump with the 40 spm speed.

a. What weighting material is used?

b. What shut-in casing pressure is input?

80. Review the Kill Graph.

81. Does pump efficiency make a difference?

a. Freeze the current line on the Kill Graph.

WELLPLANTM software internally calculates the equivalent mud gradient when performing the Well Control analysis. If the calculated equivalent mud gradient is less than the fracture gradient, the calculated gradient will be used in the analysis.



b. Change the pump efficiency for pump #1 to 90%.

c. Compare the two curves on the Kill Graph.

d. Set the pump efficiency back to 95%.

82. Access the Kill Sheet report.

a. Review report options.

b. How many sacks of weighting material are required?

c. What is the final circulating pressure?

d. How many strokes, and how many minutes does it take to fill the drill pipe?

The last page of the report contains an index to assist with locating information in the report.



Determine Critical Rotational Speeds (Using Critical Speed Module)

Input Analysis Parameters

83. Access the Critical Speed module.

84. Input the following analysis parameters.

• Torque at bit of 2000 ft-lbf

• Weight on bit of 25 kips

• Steering tool orientation of 0 degrees

• Starting speed of 20 rpm

• Ending speed of 200 rpm

• Speed increment of 5 rpm

• Excitation Frequency Factor of 3

The Critical Speed Analysis module identifies critical rotary speeds and areas of high stress concentration in the drillstring. The analysis uses an engineering analysis technique called Forced Frequency Response (FFR) to solve for resonant rotational speeds (RPMs). The Critical Speed Analysis module is based on a nonlinear finite element solution written to include intermittent contact/friction, finite displacement, buoyancy and other effects that occur while drilling.

The Critical Speed Analysis module is designed to analyze the 3D lat-eral bending vibrational responses of a bottom hole assembly. The anal-ysis can model axial vibrations (vibrations parallel to the drillstring axis), lateral vibrations (perpendicular to the drillstring axis) and tor-sional (twist) vibrations. The module includes damping and mass effects in order to more accurately represent the downhole environment.

If you use a steering tool, the orientation will be included in the analysis to determine the original position of the string in the wellbore. Steering tool parameters can be input to the mud motor using the Case > String Editor.



• Mesh from 0 to 99999 ft

a. Why are we using an excitation frequency of 3? (Hint: Look in the online help.)

b. Why do we mesh to 99999 ft? (Hint: Look in the online help.)

c. Why is Dynamics disabled?

85. Review the mesh zone parameters. Use the default parameters.

a. Why is a mesh used in the analysis?

b. In what size elements will the BHA be meshed?

c. Why is Aspect Ratio 1 the smallest ratio?

d. What is Length 2 used for?

Examine The Stresses Acting On The Workstring

86. Examine the stresses acting on the workstring.

a. What rotational speeds may result in high relative stress in the string? Look for abnormalities in the curve.

b. Where in the string are these stresses likely to occur at 140 rpm? Consider re-scaling the plot to view the data easier.

c. What components are at these points in the string?

d. What type of stress is causing the high equivalent stress?

This exercise will focus on one critical rpm at 140. In reality, you should analyze all peaks, and the range of rpms near a peak rpm. For example, for the peak at 140 rpm, we should consider between 130 and 150 rpm.

The model used is based on harmonic analysis, therefore stresses are relative and not actual.



e. Explain the difference between the View > Position Plots > Stress Components plot and the View > Rotational Speed > Stress Components plot. (Hint: Split the window and display each plot in a vertical pane.)

Examine String Displacements

87. Review string displacements.

a. Is there more relative displacement at certain rotational speeds?

b. At 140 rpm, how does the relative magnitude component stress in the MWD compare to the relative magnitude displacement in the MWD?

Review Bending Moments and Shear Stresses

88. Review bending moments and shear stress to determine if there are concerns at 140 rpm. Split the screen.

Review Results in 3D Plots

89. Access View > 3D Plots > Resultant Stresses > Equivalent. What is the advantage to using a 3D plot to review results?

Many plots have a “slider” to change analysis parameters.

Vibration may result in excessive displacement in all directions.

Use the left mouse button to zoom, rotate, and move the walls of the 3D plot.



Predict BHA Build and Drop (Using Bottom Hole Assembly Module)

Input Analysis Parameters and Review Results

90. Activate the Bottom Hole Assembly module.

91. Review the mesh zone parameters. Use the default parameters.

92. Input analysis data and review results. How is the bit tilt relative to the wellbore?

• Torque at bit is 2,000 ft - lbf

• Weight on bit is 25 kips

• Rotary speed is 120 rpm

The Bottom Hole Assembly module analyzes a bottom hole assembly (BHA) in a static “in-place” condition or in a “drillahead” mode. Many different factors influence the behavior of a bottom hole assembly. These factors include more controllable parameters such as WOB, and drillstring component size and placement, as well as less controllable items such as formation type. Because the performance of a bottom hole assembly is impacted by such a wide and varied range of parame-ters, predicting the behavior of a bottom hole assembly can be very complex.

Engineers in other fields have often relied on the Finite Element Analy-sis Method to solve complex problems. The Finite Element Analysis (FEA) method solves a complex problem by breaking it into smaller problems. Each of the smaller problems can then be solved much easier. The individual solutions to the smaller problems can be combined to solve the complex problem. Depending on the number of elements (smaller problems) that the complex structure (overall problem) is com-prised of, the solution can become very laborious. Fortunately, the com-bination of the increasing speed of computing power and creative mathematics have significantly simplified FEA analysis.

Because a bottom hole assembly is composed of many different ele-ments of varying dimensions, it lends itself quite well to the FEA method. The following sections describe the major steps performed by the Bottom Hole Assembly module while solving for an “in-place” solution, as well as a “drillahead” prediction.



• Do not check the Enable Drillahead box

93. Examine the results for drilling ahead 300 ft. Unless noted otherwise, use the same analysis data as in the previous step.

• Check the Enable Drillahead box.

• Steering tool orientation is 0 degrees

• Drill interval is 300 ft

• Overgauge is 0.5 inches

• Record interval is 30 ft

• Bit coefficient is 50

• Formation hardness is 30

• Rate of penetration is 30 ft/hr

a. What is the build rate?

b. What is the walk rate?

Determine Where BHA Contacts the Wellbore

94. Access View > Plot > Displacement.

a. Where is the BHA in contact with the wellbore?

b. What does the inclination curve represent?

95. Access View > Plot > Side Force.

a. Where are the side forces greater than zero?

b. What component has the highest side force?



Evaluate Effect of WOB and ROP

96. Activate the BHA Parametric mode.

97. Specify the following WOB and ROP data.

a. How will the build and walk rates be affected by weight on bit?

Analysis parameters are shared between modes.

WOB (kip) ROP (ft/hr)

5 15

25 35

35 50



Stuck Point Analysis (Using Stuck Pipe Module)

Input General Analysis Parameters

98. Activate the Stuck Pipe module and select the Stuck Point Analysis mode.

99. Input the analysis parameters.

• Traveling Assembly Weight is 50 kips

• Check all three Mechanical Limitations options and use the values provided.

Determine the Stuck Point

100.Compute the stuck point. Assume you were tripping out when the string became stuck. The initial load of the stretch test was 345 kips, and the final load was 365 kips. The stretch was 23.8 inches.

a. What is the measured weight when stuck?

b. Where is the stuck point?

The Stuck Pipe analysis module calculates the forces acting on the drill-string at the stuck point. It can be used to determine the location of the stuck point, the overpull possible without yielding the pipe, the mea-sured weight required to set the jars, and the surface action required to achieve the desired conditions at the back-off point.

The Stuck Pipe Module:• Includes the frictional effects of the drill string in a three-

dimensional wellbore

• Adjusts for stretch when the string is buckled.

• Uses the WELLPLANTM software Torque Drag Analysis calculations, including: equilibrium equations and stresses, stretch and buckling calculations

• Yield load limits are based on the calculated effective yield stress.

• Fatigue is not considered in the Yield Analysis



c. Is the stuck point below the jar?

Setting and Tripping the Jar

101.Activate the Jar Analysis mode.

102.Specify the following jar operating forces.

• Up set and trip forces are 10 kips

• Down trip force is 10 kips

• Pump open and seal friction forces are 5 kips

103.What are the forces to set, trip, and reset the jar?

Yielding the Pipe

104.Activate the Yield Analysis mode.

105.Determine if the loads required to set, trip, and reset the jar cause the string to fail. Is the pipe buckling or yielding?

• Minimum applied measured weight is 200 kips

• Maximum applied measured weight is 500 kips

• Increment is 10 kips

Backing Off

106.Activate the Backoff Analysis mode.

107.Determine the initial surface actions required to backoff at 19,158 ft. using the following parameters.

• Backoff force is 5 kips

Yield analysis can be performed to ensure the pipe is suitable for a jar.



• Backoff torque is 2,000 ft-lbf

a. What is the initial surface action for setup?

b. Why do you slackoff?

c. To backoff, what do you do?


ChapterDrilling Solution

Overview This chapter contains the answers for the exercises found in the previous Drilling chapter.

3

WELLPLANTM Software Version 2003.16.1.7 Training Manual Chapter 3: Drilling Solution


Torque Drag Analysis (Using the Torque Drag Analysis Module)


1. Using the Well Explorer, open the Case titled Drilling.

2. Use the Torque Drag Analysis toolbar button.

3. The Reference Datum section is located in the Well Explorer. If the Well Explorer is not displayed, click the toolbar button. If the Reference Datum is not displayed, click the

button located at the bottom of the Well Explorer.

4. Use Case > Hole Section.

a. The riser length of 590 ft (490 ft + 100 ft) is based on the Wellhead Depth (490 ft) specified on the Well Properties >

The mudline depth is 500 ft.

Chapter 3: Drilling Solution WELLPLANTM Software Version 2003.16.1.7 Training Manual


Depth Reference tab plus the Elevation (100 ft) also specified on the Depth Reference tab.

b. The default friction factors are used. These (0.2 for cased hole, and 0.3 for open hole) friction factors are the generally accepted within the industry as defaults, or a place to begin your analysis.

5. Use Case > String Editor information.

When possible, it is a good practice to correlate friction factors to existing data whenever possible.



a. The bottom of the string is at the String Depth (20,000 ft). Notice that the string is entered from Top to Bottom, therefore the bit is the bottom row of the spreadsheet.

b. The drill pipe weight includes the tool joint weight. This information can be found in the online help topic titled String Drill Pipe Data Dialog.

c. To determine the type of connections used for the drill pipe, and the make-up torque for the drill pipe connection, double-click on a non-editable cell in the spreadsheet row describing the drill pipe. The String Drill Pipe Data dialog will appear. The pipe is 5”, 19.5 lb/ft (the stated weight of 21.92 lb/ft includes the tool joints), G grade, P class pipe with a makeup torque of 21,914 ft-lbf. The connections are NC50(XH).



6. Use Case > Wellpath > Editor.

a. The current vertical section azimuth is 0.0 degrees. It is best to view the View > Wellpath Plots > Vertical Section using the same azimuth as the last survey point. In this example, the azimuth at the last survey point is 224.84 degrees. View the Vertical Section plot with the azimuth at the original 0.0 degrees, and again at 224.84 degrees.



b. Use the Azimuth field in the VSection Definition group box to set the viewing azimuth.

Vertical section plot with vertical section azimuth set to 0.0 degrees.

Vertical section plot with vertical section azimuth set to 224.84 degrees.



7. Use Case > Wellpath > Options, or click the Options button on the Wellpath Editor to specify tortuosity.

a. Apply tortuosity to the open hole sections of planned wellpaths to simulate the variations found in actual wellpaths. Applying tortuosity allows for more realistic predictions of torque and drag for planned wells. See the online help for more information.

b. When using the Sine Wave model, angle and pitch should not be a multiple of each other because the result will go to zero. Refer to the online help for an example.

c. Review the View > Wellpath Plots > Inclination and View > Wellpath Plots > Azimuth plots. The “corkscrews” are caused

Do not apply tortuosity to actual survey data.



by applying tortuosity. Tortuosity creates “ripples” in the planned wellpath.



8. Use the Case > Fluid Editor. The 13.8 OBM is used.

9. Specify the Torque Drag Analysis setup options using Case > Torque Drag Setup. The Soft String model will be used because the Use Stiff String Model box is not checked.

The teardrop next to the fluid name indicates it is the active fluid.

To activate a fluid, highlight the fluid name and then click the Activate button.



10. Use the Parameter > Mode Data dialog to review additional analysis parameters.

a. Friction factors specified on the Case > Hole Section Editor will be used because the radio button next to Hole Section Editor is selected.

b. All drilling and tripping operations will be analyzed because the box associated with each operation is checked.

c. There is either 25 kips WOB while rotating on bottom or sliding, 15 kips overpull for backreaming, and 1,500 or 2,000 ft-lbf torque (depending on the operation). WOB and torque vary depending on the operating mode.

Analyze Results at TD

11. Access the View > Table > Summary Loads table. The Measured Weight indicated in this table is the hookload.

a. Several problems exist. Refer to the online help for a definition of all failure flags.

The X flag indicates the yield strength and utilization factor is exceeded. In this example, this occurs when backreaming.



The T flag indicates the make-up torque is exceeded. In this example, this occurs when backreaming, rotating on bottom, and rotating off bottom.

The F flag indicates the fatigue endurance limit is exceeded. In this example, this occurs when backreaming or rotating off bottom.

b. Using this table it is not possible to tell where in the string the problems occur. In the following steps, we will look at other plots and tables that provide this information.

c. The overpull margin with tortuosity is 1.6 kips, and without tortuosity is 7.3 kips.

d. The overpull margin is -2.6 kips, and the yield utilization factor is exceeded during tripping out.

e. No, buckling is not predicted to occur. Notice the buckling flags (S or H) are not displayed in the table.

12. Access the View > Plot > Effective Tension plot.

a. The True Tension plot should only be used for stress analysis. If you want to determine when the string will buckle or fail due to tension, use the Effective Tension plot.



b. Notice that the tripping out operation is nearing the Tension Limit at the surface resulting in the very low overpull margin.

c. All operation curves fall to the right of the buckling curves, therefore buckling is not predicted to occur.

13. Access View > Plot > Torque Graph. Notice where the curves cross the Torque Limit line. The curves for all rotating operations indicate when the string is at TD the makeup torque is exceeded above 6,900 ft MD.

14. Access the View > Plot > Fatigue Graph. Notice the Backreaming and Rotating Off Bottom operations have a Fatigue Ratio greater than 1.0 at about 5,200 ft MD indicating a fatigue problem.

a. The fatigue ratio is the calculated bending and buckling stress divided by the fatigue endurance limit of the pipe. Fatigue analysis is important because it is a primary cause of drilling



tubular failure. A fatigue failure is caused by cyclic bending stresses when the pipe is rotated in wellbores with high doglegs.



b. Use View > Wellpath Plots > Dogleg Severity to review the doglegs. Notice the high doglegs beginning about 5,200 ft.



15. Access View > Table> Load Data.

The problems begin around 7,000 ft MD. While backreaming, the X flag in the STF column appears at 0 ft MD indicating the yield strength and utilization factor is exceed at the surface.

16.

a. Use Case > String Editor to change the drill pipe to 5”, 25.6#, S, FH, Class 1 pipe. To edit the drill pipe data, double-click on a non-editable cell in the spreadsheet row describing the drill pipe. The String Drill Pipe Data dialog will appear. Click the From Catalog button to display the Drill Pipe Specification dialog.

The flags in the STF column that indicate what limit is exceeded.



On this dialog, select the API Drill Pipe catalog from the Type drop-down list.

Double-click on each of the desired parameters to select the pipe you want to use, and then click OK.

Notice the drill pipe has been changed on the Case > String Editor.

Double-click on a non-editable cell associated with a component to view/edit the parameters defining the component.



Double-click on a non-editable cell associated with the drill pipe and review the parameters defining the pipe.

b. Review the make-up torque (View > Plot > Torque Graph) and fatigue limits (View > Plot > Fatigue Graph) for this pipe. Notice the problems are resolved.



17. Access the Normal Analysis Summary Loads table. The problems are resolved in all operation modes. Yes, it is possible the overpull is over designed.

18. You must first insert another row of drill pipe. Because we want to use the S grade pipe in the top 7,500 ft, insert a row of drill pipe below that pipe. To insert another row, highlight the existing row in the spreadsheet immediately below where you want to insert a row,



and then press the Insert key on the keyboard. A blank row will be created.

Select Drill Pipe from the Section Type drop-down list. The Drill Pipe Specification dialog will appear. Use this dialog to select the desired pipe. Click OK to close the dialog.

Because the top row of this spreadsheet is automatically calculated, to specify 7,500 ft as the length of the upper section of drill pipe, you must specify the section length in the bottom section of drill pipe as 11,568 ft. (19,068 - 7,500 ft).



Use View > Table > Summary Loads and notice the problems are resolved.

Analyze Torque and Drag at Other Depths

19. Using the Mode drop-down list, select the Drag Charts analysis mode.

20. Using the Parameter > Run Parameters dialog, analyze every 100 ft from 0 to TD. Notice much of the information on this dialog defaults from the values specified in the Normal Analysis.

21. Access the View > Plot > Tension Point/Hook Load chart.

Some longer components (drill pipe, heavy weight) are not automatically assigned a default length in the catalog.



a. The Max Weight Yield line represents the minimum yield strength of all components currently in the well at that run depth.

b. To determine the overpull at a specific run depth, subtract the Tripping Out hook load from the Max Weight Yield at the depth you are interested in. For example, the overpull when the bit is at 2,000 ft is approximately 290 kips (442 - 154).



22. Review the Torque Point chart.

a. This plot displays the torque at the surface unless the box titled Torque/Tension Point Distance from Bit box is checked on the Parameter > Run Parameters dialog.

b. There is 0 torque for trip in and trip out because the RPM field for both tripping operations is set to 0 on the Parameters > Run Parameters dialog.

When the Torque/Tension Point Distance from Bit box is checked, you can specify a specific depth where you want to know the torque acting at a particular point in the string.



23. Use the Parameter > Run Parameters dialog to enter the RPM. Notice the difference in the plot. Set the RPM back to zero.

24. Access the View > Plot > Minimum WOB chart. The results reported in the Normal Analysis Summary table assume the bit is at the string depth specified on the Case > String Editor. In this case, the string depth is set to TD (20,000 ft). Use the Data Reader



to determine what the buckling weights are at TD. The results will match.



Analyze Hydraulics (Using the Hydraulics Module)


25. Access the Hydraulics module by clicking the toolbar button.

26. Review the Case > String Editor information. To view or edit the parameters defining a component, double-click on a non-editable field associated with the component. A dialog will become available for you to edit or review the data associated with the component.

a. Double-click on a non-editable cell associated with the bit to review the bit nozzle sizes. The nozzles are 3-18/32nds.

b. Double-click on a non-editable cell associated with the mud motor to review the flow rates and pressure losses for the mud motor.



c. Double-click on a non-editable cell associated with the MWD to review the flow rates and pressure losses for the MWD.

Analyze Hole Cleaning

27. Access the Hole Cleaning - Operational analysis mode using the Mode drop-down list.

28. Use Parameter > Transport Analysis Data.

29. Review the View > Plot > Operational plot at 600 gpm and a rate of penetration (ROP) of 50. Use the sliders at the bottom of the view to change the ROP and pump rate if necessary. Use the Data



Reader toolbar button as you have in the past to determine the coordinate values on a plot

a. The minimum flow rate to clean the wellbore is about 717 gpm. This flow rate is required to clean the riser. About 614 gpm is required to clean inside the casing.

b. The bed height in the riser is less than 3 inches.

c. The bed height in the casing (between the drill pipe and the casing) is less than one half inch.

The casing shoe depth is indicated in the Bed Height plot.



d. As expected, a flow rate of 615 gpm cleaned the annulus in the cased hole section. However, there is still over 2.5 inches of bed height in the riser.

e. A flow rate of 720 gpm did clean the riser. Because 615 gpm cleaned the cased hole section, and 720 gpm cleans the riser, 105 gpm of additional flow is required to clean the riser.

f. Use Case > Hole Section Editor to add a booster pump. Double-click on a non-editable cell in the row of data



corresponding to the Riser. You must first check the Booster Pump box before you can input the booster pump information.

g. Yes, the wellbore and riser are clean.

30. Access View > Plot > Minimum flow Rate vs ROP plot.

If Catenary is selected for the Type of Riser the angle will be used in the analysis. All analysis that considers wellbore deviation will be affected.



a. If you want to drill with an ROP of 70 ft/hr and an RPM of 0, a flow rate of 646 gpm is required to clean the wellbore.

b. About 60 ft/hr.

c. Specify the rotary speed in the Rotary Speed field at the bottom of the window.

Analyze Pressure Loss and Annular Velocity

31. Access the Pressure: Pump Rate Range using the Mode drop-down list.



32. Review the surface equipment and mud pump information using Case > Circulating System.

a. The surface equipment rated working pressure is 10,000 psi

b. The maximum discharge pressure is 5,660 psi, and the horsepower rating is 2,000.

The Active box is checked to activate the pump. Only the active pump will be used in the analysis.



33. Use Parameter > Rates to specify the analysis parameters.

a. The Maximum System Pressure and Maximum Pump Power can be entered, or they can come from the active pump on the Case > Circulating System tabs. To use the pressures specified on the Circulating System tabs, click the Obtain from Circulating System button.

34. Use View > Plot > Pressure Loss plot. The system pressures losses are too high. Notice that at a 615 gpm flow rate, the system pressure losses are in the “red zone”.

The “red zone” on the Pressure Loss plot is defined as the minimum between the pump pressure and the circulating system rating.



35. Using the Case > Circulating System dialog, change from the 5660 psi pump a the 7500 psi pump.

Click the Obtain from Circulating System button to update the Pumping Constraints based on pump you selected.

36. No, there is not a problem.



37. Access View > Plot > Annular Velocity.

a. Yes, there is turbulent flow around the bottom hole assembly. Any flow rate with an annular velocity greater than the Critical Velocity (red curve on plot) is in turbulent flow.

b. Based on the flow rates and increments we are analyzing, 575 gpm is the maximum flow rate without turbulence. Use the Rescale toolbar button to enlarge a particular area of the plot if necessary. You can also review the data in grid form by clicking the Grid View toolbar button.

c. Use View > Plot > Annular Pump Rate. Over 2400 gpm would be required for turbulent flow in the riser. 834 gpm is required



for turbulent flow in the open hole, and 870 gpm in the cased hole.

38. Save your data to the database.

Determine Required Horsepower

39. Check the required horsepower using the Parameter > Rate dialog of the Pressure: Pump Rate Fixed analysis mode. Use the Mode drop-down list to select the analysis mode.

a. The stand pipe pressure is 5982 psi which is less than the 7,500 psi of the pump.



b. Using View > Pie Charts > Power > Drill String and, View > Pie Charts > Power > Annulus review the power losses in the drillstring and annulus. The power loss in the drill string is 2072 hp, and in the annulus is 38 hp. This is greater than the pump power of 2,000 hp.

c. Using View > Pie Charts > Pressure > Drill String and, View > Pie Charts > Pressure > Annulus, review the pressure losses in the drillstring and annulus. The pressure loss in the string is



5776 psi, and in the annulus is 106 psi. This is less than the pump pressure.

d. Use Case > Circulating System > Mud Pumps to activate the other pump. (Check the box next to the pump name to activate it.) Click the Obtain from Circulating System button on the Parameter > Rate dialog to include the second pump in the analysis.

e. Clear the status messages by right-clicking in the status message area, and select Clear.



Check ECD’s

40.

a. Using the View > Plot > Pressure vs. Depth plot, the string and annulus pressure stay within the pore pressure and fracture gradient boundaries.

b. The View > Plot > ECD vs. Depth plot indicates the ECD remains within the pore pressure and fracture gradient boundaries in the open hole section.



c. Hide the pore and fracture pressure curves displayed on the plot by right-clicking on the curve and selecting Hide from the right-click menu.

d. Right-click on the ECD curve, and select Freeze Line from the menu. Change the line color and thickness using the displayed dialog.

e. Use the Parameter > Rate dialog. Click OK to close the Parameter > Rate dialog. The ECD vs Depth plot will automatically be updated.

f. Refer back to the ECD vs Depth plot and notice the difference in the curves. The difference occurs because suspended cuttings are now included in the analysis. There would be a larger difference if there was a cuttings bed in the annulus.

g. The View > Plot > Depth vs Pressure and ECD Chart displays the ECD and pressure when the bit is at different depths in the open hole section. This plot can also be used to compare the



predicted standpipe pressure to equipment ratings. This is similar to the Drag Charts used in the Torque Drag analysis.

Bit Optimization

41. Access the Optimization Planning analysis mode using the Mode drop-down list. Specify the following analysis parameters using Parameter > Solution Constraints. To optimize based on Bit Impact Force or HHP we need three 15/32nd nozzles.

42. Access the Pressure: Pump Rate Fixed analysis mode using the drop-down list.

43. Use the Parameter > Rate dialog



a. The HSI is 2.6 hp/in2 using the current string nozzles.

b. Click the Nozzles button to specify the nozzle size. Use the Local tab. The String tab indicates the nozzles used on the String Editor. The TFA is 0.518 in2.



c. Be sure to un-check the Use String Editor Bit Nozzles box. The HSI is now 5.5 hp/in2.

d. Using the Rate dialog, notice the stand pipe pressure is close to the maximum pump pressure (7,500 psi), so use three 16/32nd nozzles instead. To use the three 16/32nd nozzles, click the Nozzles button and specify this nozzle configuration on the Local tab. The HSI is now 4.2 hp/in2.

e. Click the Copy to String button on the Bit Nozzles > Local tab to copy these nozzles to the String Editor.



Final Design Check

44. Select the Hole Cleaning Operational analysis mode using the Mode drop-down list. Review the View > Plot > Hole Cleaning Operational plot. There does not appear to be any issues.

45. Select the Pressure: Pump Rate Fixed analysis mode using the Mode drop-down list. Review the View > Plot > Pressure vs Depth plot. There does not appear to be any issues.



46. Access the View > Plot > ECD vs Depth plot. There doesn’t appear to be any issues.



Analyze Surge/Swab Pressures and ECDs (Using the Surge Module)


47. Access Surge analysis using the toolbar button.

48. Use Case > Pore Pressure to review the pore pressures. The over pressured zone is at 10,743.8 ft TVD. Press F11 to access the Convert Depth/EMW dialog. Specify the TVD, and click the Convert button to determine the MD.

Analyze Transient Responses

Tripping Out Operation

49. Specify operations data using the Parameter > Operations Data dialog.

50. Use the View > Operations Plot > Transient Response plot to review pressures or EMW vs Time. Use the right-click menu to select the correct plot.

a. The initial EMW on the plot is less then the original mud weight because mud temperatures effects are included in the analysis.



b. Yes, there is a problem because the EMW when the moving pipe depth is at TD falls below the pore pressure as denoted by the “red zone” on the plot.

c. About 0.25 ppg.



51. Use View > Operation Plot > Trip Schedule. The recommended safe trip speed is 150 ft/min.

52. Specify the trip speed using the Parameter > Operations Data dialog. Use View > Operation Plot > Trip Schedule to review results at all depths.Refer back to Operations Data dialog, and use 150 ft/min for the trip speed and notice the issue is resolved.



Tripping In Operation

53. Use Parameter > Operations Data to change the operation from swab to surge.

54. Use View > Operation Plot > Transient Response. The calculations cannot be performed for a surge operation when a moving pipe depth is at TD. The maximum moving pipe depth allowed is TD minus one stand length. In this example, the maximum moving pipe depth would be 19910 ft.

55. Use Parameter > Operations Data to change the moving pipe depth. There are no predicted problems.



56. Yes it is possible to experience both. Notice the following plot displays both surge and swab effects. EMW above the bold line are surge, and below the line are swab.

The conventional definition of surge operations have increases in pressure only. Transient models can predict both surge and swab pressures while running in the wellbore. Transient models have been validated using downhole tools. Refer to the online help for a list of technical references. The WELLPLANTM software Hydraulics module has a steady-state (not transient) surge/swab analysis.

The line in the middle of this plot was added to the manual to illustrate the surge (above the line) and swab (below the line) pressure responses.



Investigate Well Control (Using the Well Control Analysis Module)


57. Activate the Well Control Analysis module using the toolbar button.

58. Review geothermal data using Case > Geothermal Gradient.

59. Use Case > Well Control Setup data.

60. Review the temperature model using Parameter > Temperature Distribution.



61. Use View > Plot > Geothermal Gradient.

Determine Kick Type

62. Use the Parameter > Kick Class Determination dialog. This is a Kick While Drilling because the kick interval pressure is greater than the circulating bottom hole pressure. Refer to the online help for more information.



Estimate Influx Volume

63. Access Parameter > Influx Volume Estimation > Kick Detection Method tab. Flowrate Variation is the detection method used.

64. Parameter > Influx Volume Estimation > Reservoir tab to review the reservoir information.

Flowrate variation detects flow-out increases. Volume variation detects pit volume increases.

Some fields on the Parameter > Influx Volume Estimation tabs are disabled depending on the kick type.



65. Parameter > Influx Volume Estimation > Reaction Times tab to review the reaction time.

66. Use Parameter > Influx Volume Estimation > Results to determine the expected influx volume. It took 315 seconds to detect the expected 6 bbl kick.

Analyze Kick Tolerance

67. Access the Kick Tolerance mode using the Mode drop-down list.

68. Use the Case > Well Control Setup > Operational tab to specify the method.



69. Specify the kick tolerance analysis parameters using Parameter > Kick Tolerance.

70. Analyze kick tolerance results.

a. Use the View > Plot > Allowable Kick Volume plot. The maximum allowable influx volume is 57 bbls.



b. Use the View > Plot > Pressure at Depth plot at the shoe. The pressure is between the pore and fracture pressures while the kick is circulated out.

Use the right-click menu to select the correct plot if necessary.



c. Use the View > Plot > Pressure at Depth plot to analyze the annular pressure at the surface. Use the right-click menu to select the correct plot. The highest choke pressure is 1386 psi.



d. Review the View > Plot > Maximum Pressure plot. The Maximum Pressure plot displays the maximum annular pressures that will occur at any measured depth with an influx of constant volume in the well. The Pressure at Depth plot displays the pressure at a specified depth of interest in the annulus as the kick is circulated.



e. Access the View > Plot > Safe Drilling Depth plot. Use this plot to display the maximum pressure at a specified depth of interest using a constant influx volume occurring at the bit as the wellbore depth increases. The analysis begins at the last casing shoe depth, and continues over the distance specified as the Depth Interval to Check on the Parameter > Kick Tolerance dialog. (The ending depth of the analysis will be the casing shoe depth plus the Depth Interval to Check.)



f. Access View > Plot > Formation Breakdown Gradient plot. This plot displays the maximum pressure (expressed as a gradient) that will occur as a result of the specified influx size.



g. Use View > Plot > Full Evacuation to Gas. Yes, there will be a problem if there is a full evacuation to gas because the annular pressure exceeds the fracture gradient.



Use Animation to Review Results

71. Use the VCR buttons to start, stop, and rewind the animation. The heavy weight mud is in the wellbore and string at the end of the animation.

72. Use Case > Well Control Setup > Operational to change the kill method. The light mud is in the wellbore and string at the end of the animation.

73. Use Case > Well Control Setup > Operational tab to change the kill method.



Generate a Kill Sheet

74. Access the Kill Sheet analysis mode using the Mode drop-down list.

75. Using the Case > Well Control Setup tabs to specify the analysis parameters.

76. Click the toolbar button to access the Notebook module, and Miscellaneous mode. Use the Parameter > Leak Off Test dialog to specify the test pressure as 450 psi.



a. Use the mud density of the active fluid on the Case > Fluid Editor.

b. The leak off test was performed at the casing shoe. The casing shoe measured depth is 12,500 ft. Use the Convert Depth/EMW tool (press F11) to determine the TVD (9493.8 ft.).

c. Use the Reference Datum section of the Well Explorer to easily determine the air gap and sea depth.

d. The calculated equivalent mud gradient is the same as the fracture gradient.

77. Activate the Well Control Analysis module using the toolbar button, and the Kill Sheet mode using the Mode drop-down list.

78. Use Case > Well Control Setup to review the slow pump information.

79. Access Parameter > Kill Sheet and specify a 6 bbl pit gain. Click the Select Pump/Kill Speed button and select the pump with the 40



spm speed. Notice the other data, including the annulus and string volumes are already specified.

a. Barite is the weighting material. You can select other materials using the drop-down list.

b. The shut-in casing pressure is 500 psi.

You can click the Default from Editors button to default the annulus and string volumes based on data input in the Case > Hole Section Editor and the Case > String Editor when performing future analysis.



80. Access the View > Plot > Kill Graph.

81. Pump efficiency makes a difference.

a. Freeze the current line on the plot.

b. Use Case > Circulating System > Mud Pumps to change the pump efficiency for pump #1 to 90%.



c. Compare the two curves on the Kill Graph. Pump efficiency does make a difference. It will take more strokes with a less efficient pump.

d. Set the pump efficiency back to 95%.

82. Access the View > Report and select Kill Sheet. Click Preview to view the report.

a. Click the Report Options button to review the options.

b. 1176 sacks of weighting material are required.

c. The final circulating pressure is 774 psi.



d. It takes 4,280 strokes and 107 minutes to fill the string.



Determine Critical Rotational Speeds (Using Critical Speed Module)

Input Analysis Parameters

83. Access the Critical Speed module using the toolbar button.

84. Use Parameter > Analysis Parameters to input the following parameters.

a. We have a tri-cone bit, so we are using an excitation frequency of 3.

b. Mesh to 99999 ft. to analyze the entire string.

c. Dynamics is not checked therefore the nodal torque due to friction is not included.

85. Review the mesh zone parameters. (Parameter > Mesh Zone) Use the default parameters.

a. A mesh is used because it is a finite element analysis. The mesh is a term for describing how the string is divided into elements and nodes prior to performing the finite element analysis.

b. The BHA will be divided into elements based on the input values for Aspect Ratio 1 and Length 1. Refer to the online help for more information.



c. Aspect Ratio 1 the smallest ratio because it is used to mesh the BHA zone (500 ft in this example). It is preferable to mesh the BHA into smaller elements.

d. Length 2 is used to mesh the section of the string between the BHA and the drill pipe. The remaining pipe will be meshed using Aspect Ratio 3.

Examine The Stresses Acting On The Workstring

86. Examine the stresses acting on the workstring.

a. 140 and 35 rpm may result in high relative stress in the string. (View > Rotational Speed Plots > Resultant Stresses)

b. Use View > Position Plots > Resultant Stresses. At 140 rpm, these stresses likely to occur 12 ft (mud motor) and 37 (MWD) ft from the bit. (Use the Rescale button to enlarge a portion



of the plot. Use the Data Reader button to determine a specific value for a point on the curve.)



c. These stresses are likely to occur in the mud motor (12 ft) and MWD (37 ft).



d. Bending stress is causing the high equivalent stress in these components. If necessary, rescale the plot to view the data easier. (View > Position Plots > Stress Components)

e. The View > Position Plots > Stress Components plot displays the stress components for a range of rotational speeds. The View



> Rotational Speed > Stress Components plot displays the stress components at one rotational speed.



Examine String Displacements

87.

a. Yes, there more relative displacement at certain rotational speeds. Significant displacement is at 140 rpm, but 35 rpm and other speeds also have higher displacements. (View > Rotational Speed > Displacements)



b. Display View > Position Plots > Displacement in one vertical pane, and View > Position Plots > Resultant Stresses in the other pane. The MWD is located 30 - 47 ft from the bit. In this interval, both the displacement and resultant stress are at a peak.



Review Bending Moments and Shear Stresses

88. Split the screen. Display View > Rotational Speed Plots > Moments in one vertical pane, and View > Rotational Speed > Shear Forces in the other pane. The peaks in these plots correspond to the peak at 140 and 35 rpm we saw in other plots.



Reviewing Results in 3D Plots

89. A 3D plot is a good visual representation of two 2D plots. For example, using the Resultant Equivalent Stress plot, you can determine the equivalent stress as well as the position where the stress occurs.



Predict BHA Build and Drop (Using Bottom Hole Assembly Module)

Input Analysis Parameters and Review Results

90. Activate the Bottom Hole Assembly analysis module by clicking the toolbar button.

91. Review the mesh zone parameters using Parameter > Mesh Zone. Use the default parameters.

92. Use Parameter > Analysis to input analysis data and review results. The bit is tilted downward 0.06 degrees. The negative bit force indicates the force is acting downward. Refer to the online help for more information.



93. Examine the results for drilling ahead 300 ft. Use Parameter > Analysis to input analysis data and review results. Unless noted otherwise, use the same analysis data as in the previous step.

a. The build rate is 0.25 degrees upward.

b. The walk rate is 0.02 degrees to the left.



Determine Where BHA Contacts the Wellbore

94.

a. The BHA is in contact with the wellbore when the Clearance line is at 0 displacement. In this example, the stabilizers are all in contact. Moving up the string, the collars are also in contact. Further up, the drill pipe is in contact also.

b. The inclination curve indicates the BHA displacement is in the inclination plane. Refer to the online help for more information.



95.

a. The greatest side forces are located at the contact points we saw on the previous plot.

b. The first stabilizer has the highest side force.

Evaluate Effect of WOB and ROP

96. Select BHA Parametric from the Mode drop-down list.



97. Using Parameter > Analysis, specify the following WOB and ROP data.

a. Use View > Plot > Weight on Bit to determine how the build rate is affected by weight on bit. After 25 kips WOB, additional WOB doesn’t have much affect on the build rate. There is not much change in walk after this point either. At some point, the string settles into an equilibrium state and is less sensitive to WOB changes.



Using Stuck Point Analysis (Using Stuck Pipe Module)

Input General Analysis Parameters

98. Activate the Stuck Pipe module using the toolbar button and select Stuck Point Analysis from the Mode drop-down list.

99. Use Case > Stuck Pipe Setup to input analysis parameters.

Determine the Stuck Point

100.Using Parameter > Analysis, specify the initial load of the stretch test was 345 kips, and the final load was 365 kips. The stretch was 23.8 inches.

a. The measured weight when stuck is 405 kips.

b. The stuck point is at 19,227 ft MD.



c. Refer to the Case > String Editor. Yes, the stuck point is below the jar.

Setting and Tripping the Jar

101.Use the Mode drop-down list to select the Jar Analysis mode.

102.Use the String Jar Data dialog to specify the jar operating parameters. To access the String Jar Data dialog, double-click on a non-editable field associated with the jar on the Case > String Editor.

103.Use Parameter > Analysis to determine the forces to set, trip, and reset the jar.



Yielding the Pipe

104.Use the Mode drop-down list to select the Yield Analysis mode.

105.Use Parameter > Analysis, to determine if the loads required to set, trip, and reset the jar cause the string to fail. The pipe does not yield or buckle using the loads required to set, trip, or reset the jar. If we slackoff enough, the string will buckle (sinusoidal).

Backing Off

106.Use the Mode drop-down list to select the Backoff Analysis mode.

107.Use Parameter > Analysis to determine the surface actions required to backoff at 19,158 ft.

a. The initial surface action is to slackoff 140.8 kips.

b. Slacking off releases the tension in the string.

c. To backoff, pickup 142.3 kips.


ChapterRunning Liner

Overview

Data

The data used in this exercise is not from an actual well. Although an attempt has been made to use realistic data in the exercise, the intent when creating the data set is to display software functionality. Therefore, some data may not be realistic. Please do not let the accuracy of the data divert attention from acquiring knowledge of software functionality.

Workflow

In this section we will analyze running a liner in the wellbore section drilled in the last workflow.

Determine centralizer placement is the first step in the workflow. Both rigid and bow centralizers are used in the analysis. Comparison of the hookloads with and without centralizers is performed. Initially, a high-level torque drag analysis is performed.

A more in-depth torque drag analysis while tripping and rotating on bottom is performed. Actual load data is used to validate the selection of cased and open hole friction factors.

The Surge module is used to analyze the transient pressure (EMW) responses while running and reciprocating the liner. Mud temperature effects are examined. Conventional and auto-fill float options are investigated. A tripping schedule is generated to determine maximum trip speeds possible without exceeding the fracture gradient.

The final step in the workflow involves conditioning the well prior to cementing.

4

WELLPLANTM Software Version 2003.16.1.7 Training Manual Chapter 4: Running Liner


Workflow Solution

Solutions for the workflow steps in this chapter can be found in the Running Liner Solution chapter.

What Is Covered

During this workflow you will:

• Consider the effects of both conventional and autofill float shoes

• Analyze surge and swab transient pressures at several depths

• Review the effect of centralizers on ECD

• Review the effect of tool joints on ECD

• Analyze reciprocating the liner

Answers for the exercises in this chapter can be found in the chapter titled Running Liner Answers.

Chapter 4: Running Liner WELLPLANTM Software Version 2003.16.1.7 Training Manual



1. Using the Well Explorer, open the Case titled Running Liner.

2. Review the casing string. What is the liner overlap?

3. Ensure the mud weight is 13.8 ppg.

Centralizer Placement (Using OptiCem Module)

4. Activate the OptiCem-Cementing module.

5. Activate the Centralizer Placement analysis mode.

Using Bow Centralizers

6. Import the TrainingCentralizer centralizer catalog, and the TrainingCasingShoe catalog.

7. Select the bow centralizer in the catalog you imported. Determine the centralizer placement using the following parameters.

• Calculate centralizer placement based on standoff

• The top of the centralized interval is 15,000 ft

• Assume the cement design requires 70% standoff in centralized interval, and 40% above the centralized interval

• The maximum distance between the centralizers is 160 ft, and the minimum distance is 20 ft.

Because of the integration between the WELLPLANTM software modules, the wellbore data from the Drilling case is available to the Running Liner case.

Use the Centralizer Placement mode to calculate either the standoff yielded for a required spacing between centralizers or the spacing between cen-tralizers needed to achieve a required standoff.



• The calculated step size is 500 ft.

• The trip speed is 60 ft/min, at 0 rpm

a. What is the hookload with centralizers?

b. What is the hookload without centralizers?

c. What is the maximum hookload and where does it occur?

8. How many bow centralizers are required?

9. View a graphical representation of the hookload with and without centralizers using the Torque Drag Analysis plot. Why is there less hookload with centralizers?

10. In a future step, we will compare the hookload with bow centralizers to the hookload with a rigid centralizer. Freeze the curve representing the hookload with bow centralizer.

Using Rigid Centralizers

11. Replace the bow centralizer with the rigid centralizer from the Training Centralizer catalog. (Hint: Use a tab other than the tab displaying the Torque Drag Analysis plot.)

12. Use the same analysis parameters that you did for the bow centralizer. What is the maximum hookload and where does it occur?

Important:

In order to update results in the Quick Look section, you must click the Copy to Standoff Devices button on the Parameter > Centralizer Placement view. Therefore, if you change any data, click this button to update the results. If not, the results calculated using standoff devices may not be accurate.

If you use the same tab to display another plot or view (for example the Parameter > Centralizer Placement view) that you use to display the Torque Drag Analysis plot, any frozen lines will be lost.



13. Review the Torque Drag Analysis plot using the rigid centralizers. How does it compare to the torque drag using bow centralizers?

14. How many rigid centralizers are required? Use the same tab that you viewed the Torque Drag plot.

In-Depth Torque Drag Analysis (Using Torque Drag Module)

15. Activate the Torque Drag Analysis module.

16. Access the Drag Charts analysis mode.

17. Input the following analysis parameters.

• Analyze every 500 ft between 0 and 20,000 ft

• Analyze tripping in and out at 60 ft/min. There is no rotation.

• Analyze rotating off bottom in addition to the two tripping operations.

18. Review the hook loads for each operation with and without centralizers. Are the loads within the yield limit and rig capacity with and without centralizers when tripping out? (Hints: Use Freeze line. Use the Standoff Devices dialog to indicate when you want the centralizers used in the plot results.)

19. Include centralizers in the analysis again before proceeding.

Using OptiCem, we performed a high-level torque drag analysis. Now we can use the Torque Drag Analysis module for more in-depth analy-sis of additional operating modes.

If View > Auto Calculation is checked, anytime there is an OptiCem view, or plot open in a tab, the calculations will be performed. This is typically not desired when using another WELLPLANTM software module. Therefore, if you have an OptiCem view active in a tab, you may want to consider replacing it with the plot required for this step.



Matching Friction Factors to Actual Field Data

20. Analyze tripping in at 60 ft/min and 0 rpm every 500 ft between 10,000 and 20,000 ft.

21. Enable the sensitivity plot.

22. Input the following friction factors for sensitivity analysis.

23. Specify the following actual load data.

24. What friction factors are we currently using?

25. Do the friction factors in use (from Case > Hole Section Editor) match actual load data?

26. Is the make-up torque limit exceeded if we rotate while tripping in the liner? Analyze at 10, 15, and 20 rpm.

Casing Open Hole

Min 0.0 0.1

Increment 0.2 0.2

Max 0.4 0.5

Run Depth(ft)

Trip In Measured Weight (kips)

10,000 313

12,500 293

15,000 271

17,500 276

20,000 284



Determining Surge and Swab Pressures (Using Surge Module)


27. Access the Surge module application.

28. Review the string data.

a. Review the casing shoe information.

b. What is the difference between conventional and autofill?

c. Select the conventional float option.

d. What module uses the float option?

29. Review the standoff devices.

Specify the Operation Data

30. Specify the following operation data:

• Analyze a surge operation

• Include mud temperature effects

• Pipe acceleration and deceleration is 1 ft/sec2.

• Specify the following moving pipe depths and corresponding pipe speeds:

a. Why should you analyze 15,000 ft MD as an additional depth of interest?

Pipe Depth(MD)

Pipe Speed (ft/min)

12,500 155

15,000 155

19910 155



b. What is the length of a stand of pipe?

c. Why is the deepest pipe depth not at TD?

Analyze Transient Response

31. Review the transient EMW, at all moving pipe depths, as a function of time.

a. Is the formation fracturing at any depth?

b. Using the Transient Response plot at TD, freeze the curves that are fracturing. Change the names of the curves to indicate a conventional float is used.

32. Does auto-fill help resolve the problem? (Use a different tab to access the String Editor.)

a. Is there still the possibility of exceeding the fracture gradient at TD?

b. What is the EMW reduction at TD when the moving pipe depth is at TD?

c. Is there still the possibility of exceeding the fracture gradient at the shoe?

d. Is there still the possibility of exceeding the fracture gradient at 15,000 ft MD?

Check the Tripping Schedule

33. How can we reduce the risk of fracturing the formation by altering the trip speed?

a. What is the trip speed at TD, at the shoe, and at the depth of interest?

b. What speeds should you trip if the auto-fill becomes plugged? Compare the auto-fill results with the conventional results.

c. Enable auto-fill before proceeding.



34. Recheck the transient pressure responses to determine if there is an issue using the suggested trip speeds. Use 125, 120, and 115 ft/min for 12,500, 15,000, and 19,910 ft respectively.

Reciprocating

35. Select the Reciprocation analysis mode.

36. Specify the following analysis parameters.

• Reciprocation depth 25 ft above TD (19975 ft.)

• Reciprocation length 22 ft

• Pipe acceleration and deceleration is 0.5 ft/sec2

• No additional depth of interest

• 0 gpm flow rate

37. Are there any transient pressure issues at TD?

38. What flow rate resolves this issue?



Condition the Well Prior to Cementing (Using Hydraulics Module)

39. Access the Hydraulics module.

40. Access the Pressure: Pump Rate Fixed analysis mode.

41. Do not use centralizers in the analysis.

42. Determine how long it takes to circulate two circulations using a pump rate of 400 gpm.

43. Specify the analysis parameters. Don’t include tool joints in the analysis, but do include mud temperature effects. Analyze every 500 ft between 12,500 and TD. Circulate for 8 hours.

44. Review the ECDs as a function of depth. Freeze the ECD curve on the plot using Freeze Line.

45. Do tool joint pressure losses alter the results? If so, why? Freeze this ECD curve also on the plot using Freeze Line.

46. Include the centralizers. Is there a change in ECD? Why is the ECD increased after 15,000 ft MD?

47. What is the circulating temperature at TD, and what is the return temperature at the surface?


ChapterRunning Liner Solution

Overview This chapter contains the answers, to the exercise questions presented in the Running Liner chapter.

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WELLPLANTM Software Version 2003.16.1.7 Training Manual Chapter 5: Running Liner Solution



1. Double-click on the case name in the Well Explorer to open the Case titled Running Liner.

2. Access the Case > String Editor. The liner overlap is 250 ft. (Previous casing shoe is at 12,500 ft.)

3. Ensure the mud weight is 13.8 ppg using Case > Fluid Editor.

Chapter 5: Running Liner Solution WELLPLANTM Software Version 2003.16.1.7 Training Manual


Centralizer Placement (Using OptiCem Module)

4. Click the toolbar icon to activate the OptiCem module.

5. Activate the Centralizer Placement analysis mode using the Mode drop-down list.

Using Bow Centralizers

6. To import the catalog, right-click on the Catalogs node in the Well Explorer and select Import Catalog from the right-click menu. Using the Import Catalog dialog, navigate to the folder containing the catalog file you want to import. Be sure the Files of type: drop-down list says Catalog Transfer Files (*.cat.xml). Notice the Well Explorer now lists a catalog titled Training Centralizer. Repeat this procedure for the casing shoe catalog.

7. Use the Parameter > Centralizer Placement view. Click on the Centralizer A cell, and select Use Catalog Selector from the drop-



down list. The Centralizer Specification dialog will be displayed. Use this dialog to select the TrainingCentralizer catalog from the Catalog drop-down list. Select the bow centralizer.

Input the provided running parameters using the Parameter > Centralizer Placement view.

a. Click the Copy to Standoff Devices button on the Centralizer Placement dialog to update the Quick Look results. The hookload with centralizers is 254 kips.

b. The hookload without centralizers is 306 kips.

c. The maximum hookload is 254 kips and occurs at 20,000 ft.



8. Use Parameter > Standoff Devices to determine how many centralizers were required. In this example, 109 centralizers are required.

9. Use View > Plot > Torque Drag Analysis to view a graphical representation of the hookload with and without centralizers and compare to results using bow centralizers. There is less hookload with centralizers because there is more drag and the drag force acts in the opposite direction of motion.



10. To “freeze” a curve on a plot, click on the curve, then right-click and select Freeze Line. It is helpful to change the color, line thickness, and/or curve title to distinguish the various curves.

Using Rigid Centralizers

11. Use Parameter > Centralizer Placement. Click on the Centralizer A cell, and select Use Catalog Selector from the drop-down list. The Centralizer Specification dialog will be displayed. Use this dialog to select the TrainingCentralizer catalog from the Catalog drop-down list. Select the rigid centralizer.



12. Remember to click the Copy to Standoff Devices button.The maximum hookload is 330 kips and occurs at 8,000 ft.

13. Click the tab that contains the View > Plot > Torque Drag Analysis to compare the hookload using bow and rigid centralizers.

14. Using the same tab that you viewed the Torque Drag plot, access the Parameter > Standoff Devices to determine how many rigid



centralizers are required. Scroll to the bottom of the spreadsheet. There are 93 centralizers used.

In-Depth Torque Drag Analysis (Using Torque Drag Module)

15. Activate the Torque Drag Analysis module using the Torque Drag Analysis toolbar button.

16. Access the Drag Charts analysis mode using the Mode drop-down list.



17. Use Parameter > Run Parameters.

18. Display View > Plot > Tension Point/Hookload Chart.

Use Freeze Line to ensure the curves for running with centralizers remain so that you can compare the results to those without centralizers. (To access Freeze Line functionality, right-click on the curve, select Freeze Line, and change the properties using the displayed dialog.)



In another tab, access Parameter > Standoff Devices to indicate centralizers should not be used in the analysis. Uncheck the Use Standoff Devices box on the Standoff Devices spreadsheet.

Access the tab with the plot again. Notice the results without centralizers is now displayed on the Tension Point/Hookload Chart along with the results using centralizers. Notice that all loads, for all operations are within the yield limit of the pipe. This plot can also be used to compare the rig capacity to expected loads. In this particular case, there is 100 kips difference between the expected tripping out with centralizers load and the rig capacity.



19. Access Parameter > Standoff Devices and check the Use Standoff Devices box on the Standoff Devices spreadsheet.

As you cursor over a curve with the mouse, notice the curve turns black. The curve label in the legend also turns black. This can be helpful when determining what the curve represents. Particularly when there are several curves on the plot with the same, or close to the same color.



Matching Friction Factors to Actual Field Data

20. Use Parameter > Run Parameters.

21. Check the Enable Sensitivity Plot check box on the Run Parameters dialog.



22. Click the Input Friction Factors button on the Run Parameter dialog to access the Sensitivity Plot Friction Factors dialog.

23. Use Parameter > Actual Loads to input the actual load data.

24. Use Case > Hole Section Editor to determine the friction factors we are currently using. We are using 0.2 in cased sections, and 0.3 in open hole sections.

25. Use View > Plot > Sensitivity Plot-Tension/Hook Load Chart to determine if the friction factors in use (from Case > Hole Section Editor) match actual load data. Notice the actual load data points fall along the curve corresponding to a 0.2 friction factor in cased



hole, and 0.3 in open hole. These are the values we are using in the Hole Section Editor.

26. Use Parameter > Run Parameters to specify the rpm, and use View > Plot > Torque Point/Surface Chart. When rotating at 20 rpm, we exceed the make- up torque limit.



Determining Surge and Swab Pressures (Using Surge Module)


27. Access Surge analysis using the toolbar button.

28. Use Case > String Editor to review the string data.

a. Double-click on a non-editable cell pertaining to the Casing Shoe. The String Casing Shoe Data dialog will be displayed.

b. Click the Help button to access the online help to determine the difference between conventional and autofill options. The following is an excerpt from the online help.

c. Click the radio button associated with the conventional option.



d. The WELLPLANTM software Surge module uses the float option. This is indicated on the String Casing Shoe Data dialog.

29. Use Parameter > Standoff Devices to review the standoff devices. These are the rigid centralizers analyzed previously.

Specify the Operation Data

30. Specify the operation data using Parameter > Operations Data.



a. Consider analyzing pressured zone(s) in the open hole section. In this example, the Case > Pore Pressure spreadsheet indicates a pressured zone at 10,743 ft TVD.

Press F11 to access the Convert Depth/EMW dialog and use this dialog to determine the MD corresponding to this TVD. 10,743.8 ft TVD corresponds to 15,000 ft MD.

b. Because we are running a liner, a stand of pipe is 90 ft.

c. The deepest pipe depth is not at TD because a surge analysis cannot be performed if the bottom pipe depth is within a stand length of TD. If so, a message will be displayed in the Status Message section at the bottom of the application window, and calculations will not be performed.

Analyze Transient Response

31. Use View > Operation Plot > Transient Response Plot to review the transient pressures/EMWs, at all moving pipe depths, as a function of time. Right-click in the plot to access a menu that can be used to select a plot at a different depth. You can choose to display the data as EMW vs Time rather than Pressure vs. Time.



a. The formation is fracturing at all depths of interest using one or more moving pipe depths. Notice on the following plots the depth of interest is indicated in the plot title bar. Each curve on the plot represents the pressures or EMWs over time at that particular depth as bottom of the liner is at a specific moving pipe depth. Use the legend to determine which moving pipe depth corresponds to each curve. If a curve crosses into a red range at the top of the plot, the pressures or EMWs are fracturing the formation. Conversely, if a curve crosses into a red range at the bottom of the plot, the pressures or EMWs fall below the pore pressure and a kick may occur.

The following plot displays the results at the depth of interest (15,000 ft MD) for all three moving pipe depths. Notice that the formation fracture



gradient is exceeded at this depth when the pipe depth is at the shoe, or the depth of interest, or near TD.

Using the right-click menu again, display the results at TD. Notice the fracture gradient is exceeded when the pipe is at 19,910 ft MD, and also slightly into the red zone when the pipe is at the depth of interest (15,000 ft MD).

b. Freeze the curves that are fracturing.



32. Use Case > String Editor to change the float option to autofill.

a. Yes, there still the possibility of exceeding the fracture gradient at TD when the moving pipe depth is at TD.



b. The largest reduction, about 2.1 ppg, occurs about 0.6 minutes into tripping the stand. Use the Data Reader toolbar button to assist you.

c. Yes, there is still the possibility of fracturing the formation.



d. Yes, there is still the possibility of fracturing the formation at 15,000 ft.

Check the Tripping Schedule

33. Review the tripping schedule using View > Operation Plot > Trip Schedule.

a. The trip speed at TD, at the shoe, and at the depth of interest is 127, 125, and 117 ft/min respectively.

b. Freeze the trip speed curve generated using autofill. Using a different tab, access the String Editor and change the float



option to Conventional. Review the Trip Schedule plot again, and notice the trip speeds must be significantly reduced using conventional float option.

c. Enable auto-fill before proceeding.

34. First, using the Parameter > Operations Data dialog to specify the revised trip speeds for each moving pipe depth. Then, review the View > Operation Plot > Transient Response plot at each depth. Notice the problems are resolved.



Results at the shoe do not indicate a problem.

Results at the depth of interest, 15,000 ft, do not indicate a problem.



Results close to TD do not indicate a problem.

Reciprocating

35. Select the Reciprocation analysis mode using the Mode drop-down list.

36. Specify the analysis parameters using Parameter > Operations Data.



37. The EMW falls below the pore pressure at TD while reciprocating.

38. Use Parameter > Operations Data to specify the flow rate. Yes, the issues are resolved.



Condition the Well Prior to Cementing (Using Hydraulics Module)

39. Access the Hydraulics module by clicking the toolbar button.

40. Use the Mode drop-down list to access the Pressure: Pump Rate Fixed analysis mode.

41. Use the Parameter > Standoff Devices dialog to indicate standoff devices (centralizers) are not used in the analysis.

42. Determine how long it takes to circulate two circulations. Press F12 to determine the annular volume. Using this volume, it will approximately four hours to circulate one time.



43. Use Parameter > Rate to specify the analysis parameters.

44. Use View > Plot > ECD vs Depth.



45. Use Parameter > Rate to include tool joint pressure losses by checking the Include Tool Joint Pressure Losses box.

Use the Rescale toolbar button to enlarge the portion of the plot containing the curve data. Notice the tool joint pressure losses increase the ECD as depth increases because the tool joints reduce the annular volume. A tool joint may also result in reduced internal pip volume if the tool joint ID is less than the pipe ID.



46. Include the centralizers by checking the Use Standoff Devices box on the Parameter > Standoff Devices dialog. The centralizers also reduce the annular volume. The increase begins at 15,000 ft because that is where the centralizers begin.



47. Review the geothermal data using View > Plot > Geothermal Gradient. The circulating temperature at TD is 209 degrees F, and the return temperature at the surface is 76 degrees F.


ChapterCementing the Liner

Overview

Data


Workflow

In this section we will cement the 9 5/8” liner we analyzed in the previous workflow.

The workflow begins with a review of the centralizer placement determined in the previous workflow. The bottom hole circulating temperature is estimated.

Entering of cement job data is performed using fluids provided.

Result analysis includes analyzing: circulating pressures, downhole pressures, density and hydrostatic profiles, comparing rates in and out, wellhead and surface pressures, and estimated hookloads.

Hole cleaning (erodibility) is investigated, including the effect of remaining mud on fluid tops.

The animation is used to determine fluid tops, volumes, and other cementing parameters.

Workflow Solution

Solutions for the workflow steps in this chapter can be found in the Cementing Solution chapter.

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WELLPLANTM Software Version 2003.16.1.7 Training Manual Chapter 6: Cementing the Liner


What Is Covered

• Integration between WELLPLANTM software modules

• Defining cement slurries and spacers

• Different placement methods

• Defining a cement job, including:

• Sequence and rates fluids will be pumped

• Plugs

• Shoe tracks

• Automatic Rate Adjustments and Safety Factors

• Job stages

• Cement material requirements (sacks)

• Displacement volumes

• Surface iron works

• Estimating bottom hole circulating temperatures

• Determining pipe and annular volumes

• Specifying a gauge or washed out hole

• Using many of the available plots (as a function of time, volumes, strokes) to analyze:

• Circulating pressures

• Downhole pressures

• Density and hydrostatic pressure profiles

• Recognize when “free fall” is occurring

• Wellhead and surface pressures

• Hookloads during the job

Chapter 6: Cementing the Liner WELLPLANTM Software Version 2003.16.1.7 Training Manual


• Using the Fluid Animation to review many job parameters

• Analyzing hole cleaning during the cement job



Open the Case

1. Open the Case titled Cement Liner. We will be cementing the 9 5/8” liner we analyzed in the previous exercise.

2. Activate the OptiCem module and the Wellbore Simulator analysis Mode.

3. Keeping in mind the data integration provided by WELLPLANTM software, what data type of wellbore data do you think you will need to input to analyze a cementing case that you did not input in the Running Liner case?

Input and Review Wellbore Data

Review Hole Section, String, and Wellpath Data

4. Review the hole section data. Is the hole washed out?

5. What is the total annular volume and the annular volume in the open hole? Why is the Between Strings volume zero?

6. What is the total annular volume and the annular volume in the open hole if there is a 15% washout?

7. Set the open hole back to gauge hole.

8. Review the string data.

9. Review the wellpath editor. Is tortuosity used? Hint: Click the Options button.

If you have a Halliburton OptiCem OTC file, you can import this data directly into an open WELLPLANTM software case using File > Import. You can create a case using File > New > Instant Case.

Caliper log data can be directly imported into the Hole Section Editor using File > Import Caliper.



Define Cement Slurries and Spacers

10. Input the following fluids. All fluids use the Bingham Plastic rheology model. The 13.8 ppg OBM should already be input because it was used in the previous exercises.

Review Pore Pressure and Fracture Gradient Data

11. Review pore pressure data. Where is the maximum pore pressure in the open hole section?

12. Review the fracture gradient data. Where is lowest fracture gradient in the open hole?

Review or Input Geothermal Gradient Data

13. What is the static bottom hole temperature?

Review or Input Circulating System Data

14. Review circulating system data. What is the displacement volume in the surface iron?

Name Type Class Density (ppg)

PV @ 70 degrees

YP @ 70 degrees

Yield (ft3/sk94)

Water Req (gal/sk94)

14.0 ppg Spacer

Spacer n/a 14.0 28.0 12.0 n/a n/a

14.5 ppg Lead Cement H 14.5 39.0 9.23 1.36 5.91

16.4 ppg Tail Cement H 16.4 178.3 19.81 1.41 8.35



Centralizer Placement

15. Review the centralizer placement. Notice these are the same centralizers used in previous Running Liner case.

Specify Depths of Interest

16. Specify the depths of interest based on your answers to steps 11 and 12. Why use these depths?

Estimate Bottom Hole Circulating Temperature

17. Activate the Hydraulics module and the Pressure: Pump Rate Fixed analysis mode.

18. Specify a flowrate of 400 GPM. (This is the same flow rate used to condition the hole in the Running Liner case.) Include the effects of mud temperature in the analysis. Circulate for 9 hours. This allows for approximately 2 circulations.

19. What are the circulating annular bottom hole and surface temperatures?

You can use multiple types of centralizers. You can create a “pattern” of centralizers. For example, you can alternate between two types of centralizers, or use two of one type centralizer followed by another type. There are several patterns available for use.

It is strongly recommended that the circulating temperature profiles should be run using a temperature simulator as in WELLCAT (HCT file) or obtained data from a cementing service company. (Click Edit Profile button to input or import a temperature profile.) If this data is not available, a quick temperature analysis can be run using the WELL-PLANTM software Hydraulics module. For this exercise, we do not have an hct file, or other data, so we will use the Hydraulics module for a quick estimate of the bottom hole circulating temperature.



Input Cement Job Data

20. Activate the OptiCem module using the OptiCem toolbar button. Select Wellbore Simulator from the Mode drop-down list

21. Input BHCT, surface temperature, and the mud outlet temperature.

22. Specify the following cement job data using Parameter > Job Data. Notice that all fluids are pumped at 10 bbl/min except for the tail slurry.

• As the wellbore fluid, use the 13.8 ppg OBM. Specify a rate of 10 bbl/min. (Because this fluid is designated as the active fluid on the Case > Fluid Editor, it will appear in the top row of the Job Data dialog by default.).

• Use 50 bbls of the 14 ppg Spacer as a spacer. Pump the spacer at 10 bbl/min. (Select Spacer/Flush in the Type drop-down list.). The Placement Method is Volume.

• Pump the 14.5 ppg Lead cement at a rate of 10 bbl/min. The Placement Method is Top of Fluid and specify the top of the lead cement at 12,250 ft (at the Liner Hanger). (Select Cement in the Type drop-down list.)

• Pump 2000 ft of the 16.4 ppg Tail slurry at a rate of 7 bbl/min. (Select Cement in the Type drop-down list.). The Placement Method is Length.

• Drop a plug. To do this, add a second row of 16.4 ppg Tail slurry. Un-check the New Stage box so that this entry becomes the 4-2 stage of the tail slurry. Specify a shutdown time of 5 minutes to drop the plug.

Plugs indicate the start of the displacement, as well as act as a normal plug. In OptiCem, Top Plug with the New stage box checked, indicates the start of displacement. In this exercise, the sec-ond stage of the tail cement is an optional step to specify the time to drop the plug.



• Indicate the start of the displacement by selecting Top Plug as the Type for the row between the tail cement and the displacement fluid. Check the New Stage box.

• Pump 10 bbls of 14.0 ppg Spacer at 10 bpm on top of the plug as a post flush as an extra measure to prevent slurry contamination by displacement mud.

• Select Mud in the Type drop-down list. Displace the cement with the 13.8 ppg OBM mud pumped at 10 bbl/min.

• Because the annulus is open to the atmosphere, use 14.7 psi for the Back Pressure and use 0 bbl Return Volume.

• Use 80 ft of shoe track.

• Select Top Plug option and enter 350 PSI for bumping the plug.

• Do not automatically adjust the rates• Do not use foam cement• Do not use Inner String• Enable auto-displacement calculations. (Leave the box

unchecked.)a. How much shoe track volume is predicted?

b. How many sacks of lead and tail cement are needed for this job?

c. If the shoe track was 160 ft how many extra tail slurry sacks would be require? Important: Set it back to 80 ft after checking.

23. What is the displacement volume?

24. What is the pipe volume, and why doesn’t the displacement volume in the previous step equal the pipe volume?

Analyze Results

Review Circulating Pressures

25. Do the circulating pressures (vs. volume) during the cement job exceed the fracture pressure at the shoe?



26. Do the circulating pressures (vs. volume) cause a well control problem during placement at TD?

Review Downhole Pressure Profiles

27. Access the View > Plot > Downhole Pressure Profiles plot.

a. What would you use this plot for?

b. Is it possible to take a kick or fracture the open hole during the cement job?

c. What does the minimum hydrostatic gradient curve represent?

d. What does the maximum ECD curve represent?

Review Density and Hydrostatic Profiles

28. Access View > Plot > Final Density and Hydrostatic Profile. What do the curves represent?

Compare Rates In and Out

29. Access View > Plot > Comparison of Rates In and Out. View Results vs Time.

a. What does this plot represent?

b. Does “freefall” occur during the job?

c. Is the predicted free fall a cause for concern in this design?

d. What does the Gas Rate represent on right side of the plot?

Review Wellhead and Surface Pressures

30. Access View > Plot > Calculated Wellhead/Surface Pressure (in Time).

a. What is the maximum calculated wellhead surface pressure and when during the job does it occur?

b. What is the difference between the pump pressure and the wellhead pressure?



c. What is the maximum calculated pump pressure?

d. Why does the pressure initially drop, and then increase?

Review Hookloads

31. Access View > Plot > Hook Load Simulation.

a. Is there any danger of pumping the non-secured pipe out of the hole during the cement job?

b. Is the rig capacity exceeded?

c. Remove the line of interest from the plot. When is the maximum hookload predicted during the job?

Use the Fluid Animation to Analyze Job Parameters

32. Access View > Fluid Animation Schematic.

a. Do not include any labels on the animation, and view the animation using a 1/2 cutaway.

b. Set the down hole pointer to19,000 ft. annulus (the mid-point of the tail slurry). View the schematic To Scale.

c. Review the colors associated with each fluid. What color is associated with tail, lead, spacer, and free fall?

d. Run the simulation. What volume has been pumped when freefall occurs and the Time In is 58 minutes?

e. What is the bottom hole pressure and ECD at 19,000 ft (annulus) when free fall begins?

f. Finish the simulation.

g. What is the total time to pump the job?

h. Why is knowing the time required to pump the job important?



Review Hole Cleaning

33. Enable Erodibility and Eccentricity analysis. Specify a required shear stress (lbf/100ft2) of 20 for this exercise. Analyze between a top and bottom measured depth of 18,000 and 20,000 ft. corresponding to the tail slurry placement.

34. Access the View > Plot > Erodibility Profile plot. What is the displacement efficiency in the tail slurry section of the annulus?

35. Analyze the entire open section in the annulus.

a. Access the Analysis Data dialog, and click the Entire Open Hole Section radio button. Click OK to re-run the calculations.

b. Is the wellbore clean or is there mud cake remaining? Why is there an increase in mud cake between the previous shoe and the 15,000 ft?

c. Is the remaining mud cake a problem if only a good tail cement placement is required?

d. If a mud cake remains, what parameters, other than hole cleaning, should be re-examined?

Fine-Tune the Job

Re-Examine ECDs

36. Use the Downhole Pressure Profile plot to determine how did erodibility affected the ECDs in the open hole. Where is the increase in ECD most likely to cause a problem?

Erodibility data should be obtained from field studies, the mud company, or lab tests.

If you do not have centralizers in the analysis, and you enable the Eccentricity option, the pipe is assumed to be on the low side of the wellbore.



37. Change the fracture zone of interest from 12,500 ft to 20,000 ft.

38. Is the circulating pressure close to the fracture gradient?

39. Add a safety factor of 150 psi using automatic rate adjustment.

40. Are the circulating pressure still close to the fracture gradient? (view in volume)

41. How have the rates changed, and how many barrels will be pumped at the lower rate?

42. Access View > Plot > Downhole Pressure Profiles and notice the maximum ECD is not as close to the fracture gradient as it was prior to the rate adjustment.

Re-Examine Fluid Tops

43. Now, lets examine the top of fluids. Run the fluid animation at 19,000 ft annulus with erodibility

a. What does the red color remaining in the annulus at the end of the job represent?

b. What is the predicted top of the lead slurry with the mud remaining?

c. What is the revised predicted top of the spacer with the mud remaining?


ChapterCementing the Liner Solution

Overview This chapter contains the answers, to the exercise questions presented in the Cementing the Liner chapter.

7

WELLPLANTM Software Version 2003.16.1.7 Training Manual Chapter 7: Cementing the Liner Solution


Open the Case

1. Use the Well Explorer to open the case.

2. Use the OptiCem toolbar button to activate the OptiCem module. Select Wellbore Simulator from the Mode drop-down list.

3. WELLPLANTM software is a suite of integrated engineering applications that share data that is stored in the EDM database. Once data is input, it is shared between applications where appropriate. In fact, data stored in the EDM database can also be shared with other Landmark applications. Refer to the online help for more information about integration.

In these exercises, we are using data already entered in a previous exercise. Data already entered includes:

• Hole section data

• String data

• Wellbore fluid

• geothermal

• Wellpath

• Pore pressure and fracture gradient

• Shared centralizers

• Shared rig data

Data specifically related to a cement job that must be entered for this exercise includes:

• Slurries and spacers need to be defined using the Case > Fluid Editor.

• The sequence and volume of fluids pumped during the cementing operation must be input using the Parameter > Job Data dialog.

Chapter 7: Cementing the Liner Solution WELLPLANTM Software Version 2003.16.1.7 Training Manual


• There are other analysis parameters specific to a cementing analysis that must be specified.



Input and Review Wellbore Data

Review Hole Section, String, and Wellpath Data

4. Use Case > Hole Section Editor. No, the hole is not washed out. To indicate the hole is washed out, specify the percentage increase using the Excess (%) field.

5. The Between Strings volume pertains to an inner string configuration. If there was an inner string configuration, this volume is the volume between the inner and outer strings. (Hint: Use Tools > Volume Calculations.) The total annular volume is 2,055 bbls.

The annular volume in the open hole section is 418 bbls.



6. Use Case > Hole Section Editor and change the Excess % to 15.00 %.

The total annular volume is 2,118 bbls.

The annular volume in the open hole section is 481 bbls.

7. Use Case > Hole Section Editor and set the Excess % back to zero.



8. Use Case > String Editor. This is the same string configuration that was used in the Running Liner case.



9. Use Case > String Editor. Yes, this is the same wellpath used in the previous two designs.

Define Cement Slurries and Spacers

10. Specify the fluid data using Case > Fluid Editor.



Review Pore Pressure and Fracture Gradient Data

11. Use Case > Pore Pressure. The maximum pore pressure of 13.5 ppg is at 13,253 ft TVD.



12. Use Case > Fracture Gradient. The lowest fracture gradient of 14.75 ppg is at the prior shoe 9493.8 ft TVD

Review or Input Geothermal Gradient Data

13. Use Case > Geothermal Gradient. The BHST is 229.7 degrees F.



Review or Input Circulating System Data

14. Use Case > Circulating System Data. The displacement volume is 0.34 bbls.

Centralizer Placement

15. Use Parameter > Centralizer Placement.

Specify Depths of Interest

16. Access Parameter > Additional Data. For Reservoir Zone enter the MD of the well at TD (20000 ft) and for Fracture Zone enter



the casing shoe depth (12500 ft). We entered these depths because the MD of the well at TD has the highest pore pressure in the open hole, and the casing shoe depth has the lowest fracture gradient in the open hole. You can enter any depths of interest for these zones (weak zones or abnormal pressure zones not necessarily at prior shoe depth or well depth) if desired.

Estimate Bottom Hole Circulating Temperature

17. Click the toolbar button to access the Hydraulics module, and use the Mode drop-down list to access the Pressure: Pump Rate Fixed analysis mode.



18. Use Parameter > Rate to specify this information.

19. Access View > Plot > Geothermal Gradient. Use the Data Reader button to determine the temperatures, or click the Grid View

toolbar button to view the data in tabular form.The annular surface temperature is 73.6 degrees F.

The annular bottom hole temperature is 208.3 degrees F.

Input Cement Job Data

20. Activate the OptiCem module using the OptiCem toolbar button. Select Wellbore Simulator from the Mode drop-down list



21. Use Parameter > Additional Data. Select the BHCT option.

22. Use Parameter > Job Data.

a. 5.66 bbls of shoe track is predicted.



b. 1326 sacks of lead cement, and 467 of tail cement.

c. Approximately 23 sacks. Set the shoe track length back to 80 ft after checking.



23. Use Parameter > Job Data. The displacement volume includes the cumulative volume of fluids after the plug is dropped. 10 bbls (spacer) + 723.17 bbls (mud) = 733.17 bbls.

24. Use Tools > Volume Calculations to determine the pipe volume. The volumes are not equal because of 5.66 bbls shoe track volume.



Analyze Results

Review Circulating Pressures

25. Use View > Plot > Circ Pressure and Density - Frac Zone. (Hint: Use right-click menu to view pressure vs. volume.) No, there isn’t a problem. The circulating pressures do not exceed the fracture gradient at this depth for the entire job.

26. Use View > Plot > Circ Pressure and Density - Reservoir Zone. (Hint: Use right-click menu to view pressure vs. volume.) No, there is not a problem because the circulating and hydrostatic pressures do not fall below the pore pressure at TD during the entire job.



Review Downhole Pressure Profiles

27. Access the View > Plot > Downhole Pressure Profiles plot.

a. Use this plot for quick overall picture to determine if you will have well control or ECD issues at any depth in the open hole.

b. No, because the maximum ECD and minimum hydrostatic gradient curves lie between the pore pressure and fracture gradient curves.

c. The hydrostatic gradient curve represents the minimum gradient at any given time that could be present in the annulus.

d. This curve represents the maximum ECD’s that can be anticipated at various depths.

Review Density and Hydrostatic Profiles

28. The Density curve represents the static density of each fluid at the end of the job. The Hydrostatic Gradient curve represents the



cumulative hydrostatic gradient of all fluids in wellbore at the end of the job.

Compare Rates In and Out

29. Use the right-click menu to view Rates vs Time.

a. This plot displays the total annular return rate and corresponding pump rates versus the fluid pumped into the well (a comparison of the volume of material pumped in with the volume coming out of the well.) The difference between the two rate curves indicates free fall. If free fall occurs and well goes on vacuum, the rate out will initially exceed and then fall below the planned pumped rate.

b. There is slight free-fall at the start of displacement during the job.



c. The free fall does not appear to be severe enough. The predicted rates (in and out) are about the same for most of the job.

d. This is for foam jobs when both liquid and gas phases are present. However, it is not applicable in this design.

Review Wellhead and Surface Pressures

30. Access View > Plot > Calculated Wellhead/Surface Pressure.

a. The maximum calculated wellhead surface pressure is 2,001 psi, and occurs at the end of the job when the plug is bumped.

b. The pump pressure is at the cement unit, the wellhead pressure is at the wellhead.

c. The maximum pump pressure is approximately 2,260 psi.

d. After the heavier fluids move to the annulus, additional pressure is required to lift these fluids up the annulus.



Review Hookloads

31. Access View > Plot > Hook Load Simulation.

a. No, the predicted hookloads during the entire job are well above the neutral buoyancy.

b. No, the rig capacity is not exceeded. The calculated hookloads are below rig capacity during the entire job.

c. Click the to remove the lines of interest from a plot. Immediately after free fall occurs as the displacement fluid catches up with the tail slurry.



Use the Fluid Animation to Analyze Job Parameters

32. Access View > Fluid Animation Schematic.

a. Right-click on the plot to access the View > Animation > Fluid Positions dialog. Un-check all the boxes associated with labels, and check the 1/2 Cutaway option.

b.



c. Refer to the color legend in the upper right corner of the animation.

d. Click the button to begin the animation. 488 bbls have been pumped when free fall occurs. You can tell when free fall begins because the color indicator (black) for free fall appears. Hint: use the VCR buttons to stop, start, and step through the simulation.



e.

f. Finish the simulation.

g. 132 minutes.



h. To properly design the optimal thickening times for the slurries.

Review Hole Cleaning

33. Use the Parameter > Analysis Data dialog. Check the Erodibility and Eccentricity boxes. Click the Enter Top/Bottom MD radio button and specify the depths. Click OK and the simulation will run.

34. The tail slurry section is predicted to be fully cleaned with 100% mud removal.

35. Analyze the entire open section in the annulus.



a. Access the Analysis Data dialog, and click the Entire Open Hole Section radio button. Click OK to re-run the calculations.

b. Access View > Plot > Erodibility Profile. There is mud cake remaining. There is an increase in mud cake between the previous shoe and 15,000 ft because this interval does not have centralizers.

c. Ideally hundred percent mud removal is desirable for entire cemented section. In this exercise only a good tail placement was required and the tail section is 100% clean. In the centralized



interval containing the lead slurry, there is a small (less than 3%) mud cake.

d. Fluid tops and ECDs may be affected by remaining mud cake.

Fine-Tune the Job

Re-Examine ECDs and Fluid Tops

36. Access the View > Plot > Downhole Pressure Profile plot. Notice the increase in ECDs. The increase in ECD is most likely to cause a problem at TD.

If the design required the entire cemented section to be cleaned, the following changes could be made to the design:- a mud with a higher erodibility number could be used- improved centralizer placement over a longer interval- specially formulated spacers (for example tuned spacers) that achieve higher mud removal - use non-conventional cementing techniques (for example, foamed cement)



37. Use Parameter > Additional Data dialog. Click OK to close the Additional Data dialog and re-run the simulator to update results.

38. Access View > Plot > Circulating Pressure and Density - Fracture Zone (in volume). Notice the circulating pressure is very close to the fracture zone towards the end of the displacement at TD.



39. To add a safety factor, use Parameter > Job Data dialog to select Automatic Rate Adjustment with 150 psi safety factor.

40. Access View > Plot > Circulating Pressure and Density - Fracture Zone. Notice the circulating pressure are no longer near the fracture gradient because the rates have been adjusted towards the end of the job. Note the safety factor region has been added to the plot.

41. Access View > Plot > Comparison of Rates In and Out. Notice the rates dropped near the end of cement job. Approximately the



last 50 bbls are pumped at the slower rate of 5 bpm instead of the planned 10 bpm.

42. Access Plot > Downhole Pressure Profiles. Notice the decrease in ECD as a result of the reduced flow rates.



43. .

a. The red denotes the section where the mud was not fully removed. Use the Erodibility plot to determine the percentage of mud remaining.

b. Place the mouse pointer over the top of the lead slurry in the animation schematic to view the predicted top of lead slurry. It



is 11,813 ft (compared to previous 12,250 ft.). Fluid tops are also reported in the Wellbore Simulator report.

c. Place the mouse pointer over the top of the spacer in the animation schematic to view the predicted top of spacer. It is 11,200 ft. versus planned 11,848 ft.



If the annular volume is significantly filled with non-mobile mud, it will increase the velocity and frictional pressure losses elevating the ECDs. Also, this can cause fluid tops to be higher than anticipated. It is a good practice to review all parameters if mud displacement efficiency is not 100%.

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