Well Catt 6r1q71

™ WELLCAT :

Temperature Dependent Tubing Design Release 5000.1.13 Software Exercise Manual © 2014 Halliburton

Part Number 161484 Revision D

December 2014

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WELLCAT™ Software Release 5000.1.13 Exercise Manual Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 The WELLCAT™ Software . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 The WELLCAT™ Modules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-2 Drill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prod . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tube . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MultiString . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1-2 1-3 1-4 1-4 1-5

WELLCAT™ Applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-7 Why Are Temperatures Needed? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-8 WELLCAT™ Training Course Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-9

Getting Started . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1 Workflow Steps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-2 Workflow Solution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-5

Defining the Design, and Well and Formation Properties . . . . 3-1 Workflow Steps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-2 Workflow Solution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-5

WELLCAT™ Software Release 5000.1.13 Exercise Manual

iii

Contents

Drill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-1 Workflow Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-3 Workflow Steps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-4 Workflow Solution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-7 12 1/4” Hole Section. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-9 8 1/2” Hole Section. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-20

Drill Input Data Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-43

Prod

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1

Workflow Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-3 Workflow Steps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-4 Workflow Solution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-7 Displace to Brine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pull Workstring, Run Tubing, Set Packer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Initial production. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shut-in #1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acid Job . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shut-in #2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Produce 1 year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shut-in #3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Post-prod acid job . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shut-in #4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas lift of depleted zones . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

4-10 4-12 4-14 4-15 4-17 4-18 4-20 4-21 4-23 4-24 4-26

Prod Input Data Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-38

Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 Workflow Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-2 Workflow Steps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-3

iv


Contents

Workflow Solution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-7 Casing Input Data Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-31

Tube . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-1 Workflow Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-3 Workflow Steps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-4 Workflow Solution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-9

MultiString . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-1 Workflow Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-2 Workflow Steps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-3 Annular Fluid Expansion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-3 Wellhead Movement Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-4

Workflow Solution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-10 Annular Fluid Expansion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-10 Wellhead Movement Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-23


v

Contents

vi


Chapter 1

Introduction The WELLCAT ™ Software The WELLCAT (Well Casing and Tubing) software is an integrated suite of five modules: Drill, Prod, Casing, Tube, and MultiString. It is used to predict temperatures and pressures within the wellbore and the surrounding formation, and analyze stresses and deformation (due to buckling) in casings and tubings. It can also be used for advanced well design to predict annular pressure build-up and wellhead movement for critical applications. The following flowchart shows the interaction between the different WELLCAT modules. For example, the Tube module only uses results from the Prod module, but the MultiString module uses data from all the other four modules. Subsequent chapters discuss these relationships in more detail.


1-1

Chapter 1: Introduction

The WELLCAT ™ Modules This section briefly discusses the five modules in the WELLCAT software and their applications.

Drill The Drill module is used to perform heat transfer and fluid flow simulations during drilling, circulating, and cementing operations. The simulations are transient in nature and help build an accurate temperature history of the well during its drilling life cycle. The Drill module has built-in options that allow you to perform an easy sensitivity analysis for modeling drilling operations. Results from the Drill module can be used in the Prod, Casing, and MultiString modules. The Drill module can be used for the following applications:

1-2

•

Determining BOP and return line temperatures

•

Determining accurate cementing temperature schedules

•

Calculating an undisturbed temperature gradient from actual log temperatures

•

Modeling fluid flow hydraulics during drilling and circulation operations

•

Generating wellbore temperatures and fluid pressures that can be used in tubular stress and buckling analysis

•

Calculating initial setting conditions of casings that can be used in tubular stress analysis

•

Computing initial annular fluid temperatures used in annular fluid expansion analysis

•

Modeling a temperature history of the well that can be used while performing wellhead movement analysis



Prod The Prod module is used to perform heat transfer and fluid flow simulations during the production, shut-in, fracturing, steam injection, completion, and workover operations. The simulations are transient in nature and help build an accurate temperature history of the well. Prod has built-in options that allow you to perform an easy sensitivity analysis for modeling production operations. Results from Prod can be used in the Casing, Tube, and MultiString modules. Prod may use temperature predictions from the Drill module as a starting point for thermal calculations. The Prod module can be used for the following applications: •

Modeling fracture and acid stimulation jobs

•

Modeling water shut-off operations

•

Calculating transient wellbore temperatures and pressures during production of oil, gas, and/or water

•

Modeling gas lift operations

•

Modeling coiled tubing operations

•

Modeling water injection operations

•

Modeling effect of vacuum insulated tubings

•

Modeling permafrost formation in arctic operations

•

Predicting shut-in temperatures and pressures

•

Calculating hydraulics during circulation operations

•

Modeling kill operations

•

Modeling squeeze cementing operations

•

Modeling spot cement plugs operations

•

Generating wellbore temperatures and fluid pressures that can be used in tubular stress and buckling analysis

•

Computing producing annular fluid temperatures that can be used in annular fluid expansion analysis


1-3


Casing The Casing module is used to perform a full uniaxial and triaxial stress and buckling analysis for the casing strings inside the wellbore. This module contains numerous industry standard load cases and has the option to create custom loads to perform stress analysis. Casing has built-in options that allow you to perform an easy sensitivity analysis on load cases. Results from Casing can be used in the MultiString module. Casing may use temperature predictions from the Drill and/or Prod modules for modeling thermal loads. The Casing module can be used for the following applications: •

Performing a comprehensive casing design check

•

Performing buckling analysis on any of the casings while drilling the next hole section as well as during the producing life of the well

•

Determining wellhead loads during production

•

Computing axial stresses due to thermal loads

•

Determining suitable landing conditions to maintain casing integrity

•

Modeling bending loads that take the specified wellbore curvature and buckling effects into

•

Deg for connections

Tube The Tube module is used to perform a full uniaxial and triaxial stress and buckling analysis for the tubing strings inside the well. This module contains numerous industry standard load cases and has the option to create custom loads to perform stress analysis. Tube has built-in options that allow you to perform an easy sensitivity analysis on load cases. Results from the Tube module can be used in the MultiString module. Tube may use temperature predictions from the Prod module for modeling thermal loads. The Tube module can be used for the following applications: •

1-4

Performing a comprehensive tubing design check



•

Deg for dual tubings inside the well

•

Modeling multiple types of packers and packer setting sequences

•

Computing packer loads and reviewing the packer design envelope

•

Performing buckling analysis during production, shut-in, and workover operations

•

Performing tool age analysis

•

Determining wellhead loads during production

•

Computing axial stresses due to thermal loads

•

Deg for PBRs and packer setting conditions to maintain wellbore integrity

•

Modeling bending loads that take into the specified wellbore curvature and buckling effects

•

Deg for connections

MultiString The MultiString module is used to perform annular fluid expansion (AFE) and wellhead movement (WHM) analysis during the life of the well. This module predicts the loading conditions on the well system, taking into all the tubulars inside the well at the same time. It allows you to perform stress analysis on tubulars using some specific custom load cases. Results from MultiString can be used to create load cases in the Casing and Tube modules. MultiString may use results and data from all of the other WELLCAT modules. The MultiString module can be used for the following applications: •

Determining annular pressure build-up (APB) in each isolated annular region

•

Deg for gas caps in tubing annulus

•

Looking at various other options for alleviating annular pressure build-up issues


1-5


1-6

•

Performing stress analysis on tubulars that take annular pressure build-up pressures into

•

Modeling the loading history of the well to determine wellhead movement

•

Including compensator loads in wellhead movement analysis

•

Determining if a hanger lift-off occurs by specifying lock ring ratings and, if so, performing a progressive lift-off analysis

•

Determining loads on casings due to soil interaction

•

Performing wellhead movement sensitivity analysis by changing the point of fixity in the wellbore



WELLCAT™ Applications The WELLCAT software is used for temperature-critical applications and when an advanced casing and tubing design is necessary. Temperature-critical applications include: • • • • • •

High-pressure high-temperature (HPHT) wells Arctic or deepwater wells Wells with insulated tubing Wells in which annulus fluid expansion could be concerning Geothermal wells Hybrid/TLP wells

Advanced casing and tubing design is required for: • • • • •

Buckling and friction analysis of web tubulars Complex completions with multiple packers Cement slurry design Wellhead movement analysis Accurate thermal and pressure modeling within the wellbore

Performing a wellbore fluid flow and heat transfer simulation to predict accurate flowing and static pressures and an accurate temperature history of the well helps design tubulars for more realistic loading situations. This process takes the unknowns in the tubular design process out of the equation to create safe and reliable wells and also help with cost optimization. While creating a detailed WELLCAT model to find unknowns, you need to determine whether your intuition and experience are enough to model less realistic loading situations. You need to determine whether you are believing in myths and ignoring realities by using the load cases that are easier to model.


1-7


Why Are Temperatures Needed? Temperatures are needed for:

1-8

•

Landing conditions

•

Tubular movement and stresses = ƒ( T)

•

Buckling

•

Cement design

•

Fluid density and viscosity = ƒ(temperature)

•

Equipment limits—BOP and packer seal elements

•

Annular pressure buildup

•

Packer loads

•

Wellhead loads and movement

•

Deration of tubular strength—yield strength = ƒ(temperature)

•

Corrosive environments—material selection

•

Hydrate formation and wax deposition



WELLCAT™ Training Course Objectives This course aims to familiarize each participant with the following: •

Fundamental tubular design principles

•

Triaxial design considerations

•

Temperature and pressure simulation theory and practice

•

Wellbore data entry

•

Specification of operations and loads

•

Interpretation of results

•

Documentation of results

•

Program integration

•

Special features


1-9


1-10


Chapter 2

Getting Started In this chapter, you will become familiar with some of the basic features of the WELLCAT™ software. You will learn the types of files the WELLCAT software uses and when to use each kind. You will also learn how to configure the WELLCAT workspace. Initially, you will open an analysis file that has data entered for you. You will use this data to learn about features in the WELLCAT software that are better illustrated by using a file that has data entered, rather than requiring you to enter the data at this point in your training. After you are familiar with some aspects of the WELLCAT software, you will close the analysis file you were using and create a template file. Inventories and templates are very useful for WELLCAT s. Inventories are used to supply information for fluids, pipes, connections that are used to define strings and fluid models. Templates are used to provide you a default configuration of analysis parameters, which can include those selected from inventories. When a Design is saved to the EDM™ database or to a wcd file, the data contained in the Inventories at the time is saved also. In this chapter, you will: •

Become familiar with the files used

•

Become familiar with the overall layout

•

Access the online help

•

Customize your workspace using tabs, units, and configuration options

•

Become familiar with inventories

•

Open an existing template, configure, and then save it to a new template file for use later in the course


2-1

Chapter 2: Getting Started

Workflow Steps 1. Start the WELLCAT software. 2. Become familiar with the layout of the software. Most of the functionality is not enabled at this point, but you can hover the cursor over toolbar icons, etc to read a description or title of the item. a) How can you hide the Well Explorer? b) What version of the software are you using? c) What unit system is active? d) How can you tell what new features were added to this release? 3. Import 5000_1_13_WELLCAT_Example.wcd. What is the difference between a wcd and xml file? 4. Notice many of the functions are now enabled. a) What is the Wizard Toolbar used for? b) Why isn’t the open Design displayed in the Well Explorer? c) How can you change modules? 5. Save the Design data imported from the wcd file to the database. Although a wcd file contains Well, Wellbore, and Design data, it does not contain Site, Project or Company level data. Therefore, you must first create a Company, Project, and Site before saving the data to the database. Name the Company Example Company, the Project Example Project, the Site Example Site, and the Design Example. Accept all defaults when creating the hierarchy items. 6. How many casings are in the well? 7. Create a new tab. Name the tab Example. 8. Split the Example tab into two vertical panes. Put Results > Single Operation > Fluid Temperature into one pane, and the Well Schematic in the other.

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9. Save this configuration as a Defined Workspace. Name the Workspace Class. 10. Apply the “Example” System Workspace, and notice the tabs have changed. Reapply the Class workspace you created. 11. Using the Results > Single Operation > Fluid Temperature you placed in the Example tab, display only the Annulus curve on the plot. 12. Using the Wizard List, review the fluid temperatures for the other Prod operations. 13. Review the Engineering Options. a) Based on the options selected, will Normalized or Absolute safety factors be used for the reports and plots? b) What is the Normalized safety factor? 14. The WELLCAT software makes automatic backups. How often is a backup made? 15. Open the School template. Use File > Template > Open From File.

16. What module is active and why? 17. Review the Standard Muds in the Fluids Inventory. These fluids were in the template. Add another 17.5 ppg water based fluid titled 17.5 ppg WBM. The fluid base density is 8.33 ppg. The plastic WELLCAT™ Software Release 5000.1.13 Exercise Manual

2-3


viscosity and yield point at 70°F is 30 and 15 lb/100ft2 respectively. 18. Create a proprietary connection using the following information. •

Casing: 53.5ppf, N-80

•

Connection OD: 10 5/8”

•

Connection ID: 8 1/2”

•

Connection Grade: N-80

•

Connection Internal Pressure Rating: 9,000 psi

•

Connection Tension Rating: 1,000,000 lbf

•

Connection Compression Rating: 1,000,000 lbf

19. Save the template file using the name WELLCAT Training Template. Use File > Template > Save As.

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Workflow Solution 1. Start the WELLCAT software. 2. Become familiar with the layout of the software. Most of the functionality is not enabled at this point, but you can hover the cursor over toolbar icons, etc to read a description or title of the item. Show or hide the Well Explorer.

Version number

Well Explorer

Active unit system

a) How can you hide the Well Explorer? See previous image. b) What version of the software are you using? See previous image. c) What unit system is active? See previous image.


2-5


d) How can you tell what new features were added to this release? Use Help > WELLCAT Release Notes.

3. Import 5000_1_13_WELLCAT_Example.wcd. What is the difference between a wcd and xml file? Use File > Import > WCD. WCD files are “flat” files and do not contain any database hierarchy information. This type of file was used predominately prior to the WELLCAT software using the EDM database. XML, or EMD.XML files contain associated database hierarchy data as well as WELLCAT specific data.

2-6

File Extension

Use in the WELLCAT software

XML, or EDM.XML

EDM transfer files

WCD

Well files created using the WELLCAT software

WCT

Template files created using the WELLCAT software

LIB

File containing a library of inventory data

RPT

Files containing reports you created using the WELLCAT software

SCK

Well files created using the StressCheck software

DAT

Various files including: unit systems created using the WELLCAT software, pipes, connections, API couplings, and Multax input files

DXT

Data exchange template file

DXD

Data exchange import/export file

WPI

Input files from the DOS version of the WELLCAT software



4. Notice many of the functions are now enabled. Click the Input button to toggle between using the Wizard List for input dialogs, or to change the operation/load displayed in the active single result plot. Wizard Toolbar

a) What is the Wizard Toolbar used for? The Wizard Toolbar provides easy access to common data entry forms and result views. The contents of the Wizard List will change depending on the selected module or result. All items listed in the Wizard List can also be selected using the Wellbore, Operations, Loads, Analysis, and Results menus. b) Why isn’t the open Design displayed in the Well Explorer? Only Designs saved to the database are displayed in the Well Explorer.


2-7


c) Use the module icons to change modules.

5. Save the Design data imported from the wcd file to the database. Although a wcd file contains Well, Wellbore, and Design data, it does not contain Site, Project or Company level data. Therefore, you must first create a Company, Project, and Site before saving the data to the database. Use any name you prefer, and accept all defaults when creating the hierarchy items. Use File > New >

2-8



Company to create the Company. Follow the prompts to create the Project and Site.


2-9


Use File > Save > Save to Database, and select the Site you created.

Name the Design Example.

2-10



Notice the Well, Wellbore, and Design are created and visible in the Well Explorer. The name for the Well was provided in the WCD file.

6. How many casings are in the well? There are several ways to determine the number of casings.

The Associated Data Viewer provides information about the item selected in the Well Explorer, including the number of casings.

Wellbore > Well Schematic > General provides a view of the well configuration.


2-11


Wellbore > Casing and Tubing Configuration is used to enter casing and tubing information. Data in the bottom spreadsheet (the String Sections) pertains to the highlighted row in the top spreadsheet.

7. Create a new tab. Name the tab Example. Use Tools > Tabs.

2-12



Tab is displayed.


2-13


8. Split the Example tab into two vertical panes. Put Results > Single Operation > Fluid Temperature into one pane, and the Well Schematic in the other.

Use the Splitters to divide the window.

9. Save this configuration as a Defined Workspace. Name the Workspace Class. Use File > Workspace > Save.

Notice the workspace you created is displayed in the Defined Workspace section.

10. Apply the “Example” System Workspace, and notice the tabs have changed. Reapply the Class workspace you created. To apply a workspace, double-click on the workspace name in the Well Explorer.

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11. Using the Results > Single Operation > Fluid Temperature you placed in the Example tab, display only the Annulus curve on the plot. Right-click and select Data Selection and remove the check from Tubing/Workstring.

12. Using the Wizard List, review the fluid temperatures for the other Prod operations. Be sure the Input button is not pressed.

Use the arrows to scroll through the operations.

13. Review the Engineering Options. Use Tools > Options > Engineering.


2-15


a) Based on the options selected, will Normalized or Absolute safety factors be used for the reports and plots? Normalized safety factors are used.

b) What is the Normalized safety factor? Press F1 or the Help button to review the online help.

2-16



14. The WELLCAT software makes automatic backups. How often is a backup made? Use Tools > Options > General.

Backups are set to occur every 10 minutes.

15. Open the School template. Use File > Template > Open From File.


2-17


16. What module is active and why? The Prod module is active because it was the active module when the template was saved.

17. Review the Standard Muds in the Fluids Inventory. These fluids were in the template. Add another 17.5 ppg water based fluid titled 17.5 ppg WBM. The fluid base density is 8.33 ppg. The plastic viscosity and yield point at 70°F is 30 and 15 lb/100ft2 respectively.

Plastic viscosity and yield point vary with temperature and pressure. Enter the reference temperature for these input properties. The reference pressure is assumed to be atmospheric. Plastic viscosity and yield point are important when the fluid is used as a flowing fluid. These properties are less sensitive for annular fluids.

18. Create a proprietary connection using the following information.

•

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Casing: 53.5ppf, N-80



•

Connection OD: 10 5/8”

•

Connection ID: 8 1/2”

•

Connection Grade: N-80

•

Connection Internal Pressure Rating: 9,000 psi

•

Connection Tension Rating: 1,000,000 lbf

•

Connection Compression Rating: 1,000,000 lbf

19. Save the template file using the name WELLCAT Training Template. Use File > Template > Save As.


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2-20


Chapter 3

Defining the Design, and Well and Formation Properties In this exercise, you will define the common well information used in the exercises for all five modules in this manual. The data will be entered using the Well Explorer or the Wellbore menu. Depending on the module you are in, different Wellbore menu items are active and available to enter input information, while others are grayed out. Wellbore menu options that are specific to a specific workflow will be discussed in that worflow. In the exercise, you will define the following information: •

Use the Well Explorer to define the data hierarchy including: — — — — — —

•

Company Project Site Well Wellbore Design

Use the Wellbore menu to define well and formation data, including: — — — — — — — — — — —

General data Wellpath data Undisturbed temperature profile Casing and tubing configuration details Annulus content details Cement properties Pore pressure profile Fracture gradient profile Lithology Formation properties Soil properties


3-1

Chapter 3: Defining the Design, and Well and Formation Properties

Workflow Steps 1. Create the Company that will be used in this course. Name the company WELLCAT Training. 2. Create the Project. Name the project WELLCAT Training Project. The System Datum Description is Mean Sea Level, and the Project Units are API. a) What does having Unrestricted for the Tight Group Name mean? b) What is the System Datum Description used for? 3. Create the Site. Name the Site WELLCAT Training Site. The Default Site Elevation is 100 ft above the system datum. What will be the default datum for all wells associated with this site? 4. Create the Well. Name the Well WELLCAT Training Well. This well is offshore in 300ft of water. The datum name is RKB and is 100 ft above MSL. The wellhead elevation is 60ft from MSL. 5. Create the Wellbore. Name the Wellbore WELLCAT Training Wellbore. 6. Create a prototype Design. Name the Design WELLCAT Training Design. Why are we using a prototype Design? 7. Open the Design. 8. Apply the WELLCAT Training Template you created. 9. Indicate that all casing strings for this well extend from the mudline to the surface wellhead. The depth of the well is 17,500 ft MD. 10. This well is deviated. Enter the following data to define the wellpath. What is Max DLS used for? MD

3-2

Inclination

Azimuth

Max DLS

0

0.0

0

2,100

0.0

0

0.0

3,350

25.0

0

2.0



MD

Inclination

Azimuth

Max DLS

14,500

25.0

0

0.0

15,000

15.0

0

2.0

17,500

15.0

0

0.0

11. Indicate the surface ambient and mudline temperature is 40ºF, and the temperature at the well total depth, 16,300 ft TVD, is 380.0º F. 12. Specify the following casing and liners for this well. OD (in)

Name

Type

MD Hangar (ft)

MD TOC (ft)

MD Base (ft)

Pipe Weight (lb/ft)

Pipe Grade

Hole Size

Annulus Fluid

30

Conductor

Drive pipe

40

N/A

600

309.7

X-52

N/A

N/A

20

Surface

Casing

40

450

2,000

94.0

K-55

26

Seawater

13 3/8

Intermediate

Casing

40

6,000

9,700

77.0

N-80

17 1/2

10.0 ppg WBM

9 5/8

Protective

Casing

40

9,500

15,000

53.5

N-80

12 1/4

14.5 ppg OBM

7

Production

Liner

14,800

14,800

17,500

32.0

C-95

8 1/2

17.5 ppg OBM

7

Production

Tie-back

40

14,800

14,800

38.0

C-95

N/A

17.5 ppg WBM

3 1/2

Production

Tubing

40

N/A

17,000

12.7

C-75

N/A

10.0 ppg CaCl2

a) What fluid is used to drill the 17 1/2” hole? b) What fluid is used to drill the 12 1/4” hole? 13. After the cement is set, what fluids are in the annulus of the 9 5/8” casing? Add a 14.6 ppg spacer from 9,400 - 9,500 ft MD. 14. Where are the thermal properties of the fluids in the annulus specified? 15. Where are the thermal properties of the pipe and other structural elements specified? 16. Where are the thermal properties of the formation specified?


3-3


17. Specify the pore pressure and fracture gradient as indicated below. Vertical Depth (ft)

Pore Pressure (psi)

EMW (ppg)

Permeable Zone

400

134.03

6.45

No

9066

4568.32

9.70

No

13885

10278.50

14.25

No

16300

14606.48

17.25

No

Vertical Depth (ft)

Fracture Gradient (psi)

EMW (ppg)

400

187.01

9.00

8000

6025.97

14.50

12000

10597.39

17.00

16300

16935.05

20.00

a) Can pore and fracture gradient data be imported? 18. Save and close the design.

3-4



Workflow Solution 1. Create the Company that will be used in this course. Name the company WELLCAT Training. Use File > New Company.

2. Create the Project. Name the project WELLCAT Training Project. The System Datum Description is Mean Sea Level, and the Project Units are API. Use File > New Project.

a) What does having Unrestricted for the Tight Group Name mean? All s will be able to view this project.


3-5


b) What is the System Datum Description used for? It is the absolute zero height or depth for the Project and is the depth from which all Wellbore depths are measured. 3. Create the Site. Name the Site WELLCAT Training Site. The Default Site Elevation is 100 ft above the system datum. What will be the default datum for all wells associated with this site? Use File > New > Site. The Default Site Elevation will be the default datum for all wells associated with this site.

4. Create the Well. Name the Well WELLCAT Training Well. This well is offshore in 300ft of water. The datum name is RKB and is

3-6



100 ft above MSL. The wellhead elevation is 60ft from MSL. Use File > New > Well.


3-7


5. Create the Wellbore. Name the Wellbore WELLCAT Training Wellbore. Use File > New Wellbore.

6. Create a Design. Name the Design WELLCAT Training Design. Use File > New > Design. Refer to the online help for a description of Designs. Prototype designs are used when analyzing. After you

3-8



decide on a particular prototype design, you can change the Phase to Planned to indicate it is the design you plan to drill.

7. Open the Design by double-clicking on the Design name in the Well Explorer. 8. Apply the WELLCAT Training Template you created. 9. Indicate that all casing strings for this well extend from the mudline to the surface wellhead. The depth of the well is 17,500 ft MD. Use Wellbore > General or the Wizard to access the General dialog. In the Location field, a well can be specified as Onshore, Platform, Subsea, or TLP. Based on the input information in the Well Properties dialog box of the design, some of these choices may not be available. Select Platform to indicate all casing strings extend from the mudline to the surface wellhead.

The reference point data is obtained from the information specified in the Well Properties dialog box for the design.


3-9


10. This well is deviated. Enter the following data to define the wellpath. MD

Inclination

Azimuth

Max DLS

0

0.0

0

2,100

0.0

0

0.0

3,350

25.0

0

2.0

14,500

25.0

0

0.0

15,000

15.0

0

2.0

17,500

15.0

0

0.0

Use Wellbore > Wellpath Editor.

Max DLS specifies the maximum dogleg severity for the course length between the preceding and current rows. Max DLS does not affect the definition of the actual well trajectory, and is used only for calculating bending stress over the corresponding interval. Max DLS defaults to the calculated or -specified DLS value for the corresponding line, but you can re-specify it. 11. Indicate the surface ambient and mudline temperature is 40ºF, and the temperature at the well total depth, 16,300 ft TVD, is 380.0º F. Use Wellbore > Undisturbed Temperature. How could you specify a non-linear temperature profile?

This option is only available in the Drill module.

3-10



Use the Additional tab to specify a non-linear temperature profile.

12. Specify the following casing and liners for this well. Use Wellbore > Casing and Tubing Configuration. OD (in)

Name

Type

MD Hangar (ft)

MD TOC (ft)

MD Base (ft)

Pipe Weight (lb/ft)

Pipe Grade

Hole Size

Annulus Fluid

30

Conductor

Drive pipe

40

N/A

600

309.7

X-52

N/A

N/A

20

Surface

Casing

40

450

2,000

94.0

K-55

26

Seawater

13 3/8

Intermediate

Casing

40

6,000

9,700

77.0

N-80

17 1/2

10.0 ppg WBM

9 5/8

Protective

Casing

40

9,500

15,000

53.5

N-80

12 1/4

14.5 ppg OBM

7

Production

Liner

14,800

14,800

17,500

32.0

C-95

8 1/2

17.5 ppg OBM

7

Production

Tie-back

40

14,800

14,800

38.0

C-95

N/A

17.5 ppg WBM

3 1/2

Production

Tubing

40

N/A

17,000

12.7

N-80

N/A

10.0 ppg CaCl2


3-11


After a string is defined in the Casing and Tubing Configuration spreadsheet, you must define the details of the string in the String Sections spreadsheet before you enter the next string

If the Annulus Fluid you want to use does not exist, select Inventory from the drop-down and use Inventories > Fluids to create it.

3-12




3-13


3-14



a) What fluid is used to drill the 17 1/2” hole? 10 ppg WBM b) What fluid is used to drill the 12 1/4” hole? 14.5 ppg OBM 13. After the cement is set, what fluids are in the annulus of the 9 5/8” casing? Use Wellbore > Annulus Contents.

Annular contents after cementing.

14. Where are the thermal properties of the fluids in the annulus specified? Use Inventories > Fluids to specify the rheological and other fluid parameters used to calculate fluid thermal properties. Use Inventories > Cement Properties to specify the thermal properties of cements.

15. Where are the thermal properties of the pipe and other structural elements specified? Inventories > Heat Conduction Properties is used to specify the thermal properties for materials used for risers, coiled tubing, drill pipe, tubing, casing, and other structural elements except for drill collars.


3-15


16. Where are the thermal properties of the formation specified? Use Inventories > Formation/Soil Properties to specify the thermal and physical formation properties.

You can define many different formations. Use Wellbore > Lithology to indicate which formation the well intersects.

17. Specify the pore pressure and fracture gradient as indicated below. Vertical Depth (ft)

EMW (ppg)

Permeable Zone

400

134.03

6.45

No

9066

4568.32

9.70

No

13885

10278.50

14.25

No

16300

14606.48

17.25

No

Vertical Depth (ft)

3-16

Pore Pressure (psi)

Fracture Gradient (psi)

EMW (ppg)

400

187.01

9.00

8000

6025.97

14.50

12000

10597.39

17.00

16300

16935.05

20.00



Use Wellbore > Pore Pressure and Wellbore > Fracture Gradient. Enter data from the top down. This data will be used in all WELLCAT modules. Pressures can only be entered on a TVD basis and can be specified as either a pressure or an equivalent mud weight (EMW). The WELLCAT software will automatically calculate the other value based on the specified TVD.

The base of the zone is assumed to be the depth of the next data point. Permeable zone data can be used to calculate external pressure profiles.

a) Can pore and fracture gradient data be imported? The pore pressure and fracture gradient data can also be imported from a text file using File > Import. The data in the text file must be in ASCII format and must only contain rows of numeric data with at least two columns (the other columns are ignored) that may be delimited by spaces, commas, or tabs. The first column must contain depths data and the second column must contain pressure values. 18. Save the Design by clicking . Right-click on the Design name in the Well Explorer and select Close.


3-17


3-18


Chapter 4

Drill The WELLCAT™ software Drill module is a thermal and pressure simulator. It is used to simulate fluid flow and heat transfer in the wellbore and the surrounding formation during drilling operations. It has the capability to model a full transient fluid flow and heat transfers solution. Results from the Drill module are available for use during stress analysis inside the Casing module as well as for annular pressure build-up and wellhead movement analysis inside the MultiString module. Drill module is an advanced engineering tool used for predicting: •

Temperatures and pressures while drilling, conditioning hole, running casing, and logging.

•

Cement circulation and setting temperatures.

•

High-pressure high-temperature hydraulics.

•

Downhole tool temperatures.

•

Casing service loads during drilling.

•

Undisturbed temperature profile from log data.

Drill has the following functional features: •

Modeling of thermal disturbances caused by drilling by entering the drilling days, rotating hours, average flow conditions, bit, and BHA data as input

•

Computation of drilling fluids and cement density and rheology as a function of temperature and pressure

•

Simulation of vertical and deviated wells as well as onshore and offshore wells

•

Determination of undisturbed temperature profile from log data

•

Determination of circulation temperatures, pressures, and effective circulating densities for drilling, hole conditioning, and cementing operations

•

Modeling of casing and liner cementing, cement squeezes, and cement plug operations

•

Calculation of slurry placement temperatures and temperature build-up while waiting on cement


4-1

Chapter 4: Drill

•

4-2

Determination of post-cementing casing temperatures for landing and casing temperatures during drilling of deeper intervals


Chapter 4: Drill

Workflow Overview In this section of the course, you will learn how to use the Drill module using the design created in previous chapter. You will define: •

Time required to trip drill pipe, the bottom hole assembly, and logging tools

•

Drilling operations performed while drilling, logging, and conditioning the 12 1/4” and 8 1/2” hole sections

•

Operations for running and cementing the 9 5/8” casing, 7” liner, and the 7” tie-back

After you have defined all the drilling operations, you are ready to calculate and view the results of the thermal simulations. You will learn how to calculate results in the Drill module and then view them for analyzing.


4-3

Chapter 4: Drill

Workflow Steps 1. Import the file 5000_1_3_WELLCAT_Start_Drill.edm.xml. 2. In the WELLCAT Training Company, open the WELLCAT Training Design. 3. Activate the Drill module if not already active. 4. Specify the following trip times for various drilling operations. Operation

Time (hr/1000ft)

Drill Pipe, trip in and out

0.40

BHA, trip in and out

0.40

Log Travel In

0.50

Log Travel Out

1.00

5. Create the following operations: Operation Name

Operation Type

Prior DRILL Operation

Next Casing String

Drill 12 1/4” Hole

Drilling

Undisturbed

9 5/8” Protective Casing

Logging 12 1/4” Hole

Logging



Condition 12 1/4” Hole

Trip Pipe & Circulate



Run 9 5/8” Casing

Run Casing & Circulate



Cement 9 5/8” Casing

Primary Cementing

Run 9 5/8” Casing


Drill 8 1/2” Hole

Drilling


7” Production Liner


Logging

Drill 8 1/2” Hole






Run 7” Liner




Cement 7” Liner

Primary Cementing

Run 7” Liner


Clean-up Liner for Tie-back


Cement 7” Line


4-4


Chapter 4: Drill

Operation Name

Operation Type


Next Casing String

Run and Set 7” Tie-back


Clean-up Liner for Tieback

7” Production Tie-back

Use the excerpts from the Results > Reports > Drill Input Data report on the section titled “Drill Input Data Report” on page 43. When entering the operational parameters: • Because we often want to use the temperature calculated by the preceding operation, use the Initial Mud Pit Temperature calculated by the software for all operations except for the first operation, and for all operations using a new fluid. • In order to update the calculated values, sometimes it is necessary to highlight the value, click the Backspace key, and then click the Tab key to refresh the calculated field. • Although it is not necessary to input the operations on the Operations > Drilling Operations dia the order they are performed, it is easier. In any case, be sure to select the correct Prior DRILL Operation on the Drilling Operations tab. • Operations can be dragged into the correct position in the Name list by clicking the left mouse button when an operation is highlighted, moving the cursor to where you want to drop it, then releasing the mouse button. • It is a good practice to calculate results ( ( )data

) and save

• To reduce the time required to create an operation, consider using the Copy Op functionality to create similar operations. When using this functionality, it is important to ensure the copied parameters are edited to correctly reflect the operation details. • Similarly, consider using the Copy Prev functionality on the Drill String tab to use a string from a previous operation, either as it is, or with modifications. 6. Calculate Drill Module results. 7. At the end of the Drill 12 1/4” Hole operation, what is the temperature of the fluid in the annulus?


4-5

Chapter 4: Drill

8. Does the Number of Trips considered in the analysis change the results much in this example? Compare results using 1 and 4 trips for the Drill 12 1/4” Hole operation. to Copy Op. 9. There is no circulation in a logging operation. What do you think will happen to the annular fluid temperature when you are not circulating? Compare the results for the Drill 12 1/4” Hole, Logging 12 1/4” Hole, and Condition 12 1/4” Hole operations. 10. WELLCAT does not have a BOP Test operation type. If you wanted to model a BOP test, what type of operation would you use? 11. If you pump faster during a circulation operation, will it always lower the temperature in the annulus? Analyze the Condition 12 1/ 4” Hole operation while circulating at 500, 600, 650, and 700 gpm. 12. What could be causing this? How does fluid flow change with flow rate? Use the Flow Summary. 13. When you review the results for an operation, at what time in the operation do the results represent? 14. At the end of the Drill 12/14” Hole and the Logging 12 1/4” Hole operations, how far out from the center of the wellbore has the formation temperature increased? 15. Is the ECD in the safe range for all operations?

4-6


Chapter 4: Drill

Workflow Solution 1. Import the file 5000_1_3_WELLCAT_Start_Drill.edm.xml. Use File > Import > Transfer File. Overwrite any existing data. 2. In the WELLCAT Training Company, open the WELLCAT Training Design. Double-click on the Design name in the Well Explorer to open it. 3. Activate the Drill module. Activate the Drill module by clicking the toolbar button. 4. Specify the following trip times for various drilling operations. Operation

Time (hr/1000ft)

Drill Pipe, trip in and out

0.40

BHA, trip in and out

0.40

Log Travel In

0.50

Log Travel Out

1.00

Specify the time required to trip, and log. Use the Operations > Operation Times dialog box to enter operational times for tripping of pipe, BHA, and electric logging tools. In this exercise the default values are used. However, you can edit these values to reflect your rig handling equipment and rig hand experience.


4-7

Chapter 4: Drill

5. Click the Operations > Drilling Operations > Details button to define the details of a drilling operation you have created. The Drill Operation Details dialog contains several tabs for you to define the drilling operation parameters. The tabs available are determined by the selections made in the Drilling Operations dialog.Create the following operations: Operation Name

Operation Type


Next Casing String


Drilling

Undisturbed



Logging







Run 9 5/8” Casing





Primary Cementing

Run 9 5/8” Casing


Drill 8 1/2” Hole

Drilling




Logging

Drill 8 1/2” Hole






Run 7” Liner




Cement 7” Liner

Primary Cementing

Run 7” Liner




Cement 7” Line





7” Production Tie-back

Use the excerpts from the Results > Reports > Drill Input Data report on the following pages for operation parameters. When entering the operational parameters: • Because we often want to use the temperature calculated by the preceding operation, use the Initial Mud Pit Temperature calculated by the software for all operations except for the first operation, and for all operations using a new fluid. • In order to update the calculated values, sometimes it is necessary to highlight the value, click the Backspace key, and then click the Tab key to refresh the calculated field.

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Chapter 4: Drill

• Although it is not necessary to input the operations on the Operations > Drilling Operations dia the order they are performed, it is easier. In any case, be sure to select the correct Prior DRILL Operation on the Drilling Operations tab. • Operations can be dragged into the correct position in the Name list by clicking the left mouse button when an operation is highlighted, moving the cursor to where you want to drop it, then releasing the mouse button. • It is a good practice to calculate results ( ( )data

) and save

• To reduce the time required to create an operation, consider using the Copy Op functionality to create similar operations. When using this functionality, it is important to ensure the copied parameters are edited to correctly reflect the operation details. • Similarly, consider using the Copy Prev functionality on the Drill String tab to use a string from a previous operation, either as it is, or with modifications.

12 1/4” Hole Section

Drill 12 1/4” Hole To create a drilling operation, access the Operations > Drilling Operations dialog. Use the Drilling Operations dialog to give the operation a name and to specify when the operation occurs. You must then specify many details that define that operation.


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Chapter 4: Drill

Using Operations > Drilling Operations: • Select an Operation type. • Define a Prior DRILL Operation. • Specify the Next Casing String. • Click Details to display the Drill Operation Details tabs. • Enter required data on the Details tabs. This data can be found in Section , “Drill Input Data Report,” on page 43.

The information displayed on this dialog corresponds to the selected operation.

Select the operation type that best describes the operation. Use the Prior Drill Operation list to assign the operation a place in the sequence of operations. Use the Next Casing String list to select the next casing string to be run after this operation.

Each of these distinct activities is first created and listed in the Operation Name section of the dialog. The rest of the dialog displays the data corresponding to the currently selected operation. To create an operation, simply type the new name in the next empty space in the box at the end of the list.

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Click the Details button to specify additional information about the operation.

Chapter 4: Drill

Usually the Start and End depths are for an entire hole phase. Default values are based on data in the Wellbore > Casing and Tubing Configuration spreadsheets. However, you could specify a smaller interval if you want to enter separate bit runs. You can also extend the end depth for a rat hole.

For Number of Trips, the initial trip in and the final trip out are considered one round trip. Specify the days to drill, including onbottom time and trip time.

The time to pull out of the hole is based on times input on the Operation > Operations Times dialog. The Booster Pump section is only available if a riser is present.

The Circulation on bottom before Pull Out of Hole field indicates the conditioning and hole cleaning period at TD

Use the Operations > Drilling Operations > Details > Drilling tab to define the parameters required to model the activities during a drilling operation. The Drilling Operation Type models drilling from the prior casing shoe to the setting depth of the associated pipe. A series of tripping and drilling operations are simulated in this event. If desired, the drilling interval can be subdivided into several Drilling operations. The drilling process disturbs the wellbore, heating the upper sections and cooling the lower sections. This situation can have significant effects on temperatures experienced in subsequent operations. Results for this operation include temperature build-ups with time of the temperature and pressure profiles while circulating at the interval total depth.


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Chapter 4: Drill

Use the Drilling Fluid tab to specify the drilling fluid used for the operation, and how the temperature of the drilling fluid will be modeled as it is being pumped into the well. Consider using Use Average Inlet Temperature in situations where you want to indicate the mud is entering at a constant temperature, such as when you are not taking returns, you are drilling an HTHP well that requires the mud be kept at a constant temperature, or you are using a cooling system. The Drilling Fluid default value comes from the Wellbore > Annulus Contents tab. Mud Pit Geometry assumes all pits are the same size. The analysis will assume that each pit has an agitator contributing to the temperature of the mud.

The Environment section is used for computing convective heat transfer across the mud pit surface.

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Initial Mud Pit Temperature is a calculated field if you have calculated results for the previous operation. Do not be concerned if the temperature you see does not match this screenshot. In this example, results have been calculated so, this is a calculated temperature.


Chapter 4: Drill

Use the Drill String tab to define the drill string for the current operation. The drill string can include drill collars, drill pipe, heavy-weight drill pipe (HWDP), and a bit.

Use this drop-down list to select a previously defined drillstring. The options for Pipe and Connection are all populated with options entered into the corresponding inventory. If you do not see what you need, you must input it into the corresponding inventory.

Logging 12 1/4” Hole For the logging operation, specify a 24 hr logging time. To validate the simulation data, you will enter a recorded logging temperature of 300° F logging at 15,000 ft MD 14 hours after the start of logging period.


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Chapter 4: Drill

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Chapter 4: Drill

Condition 12 1/4” Hole The 12 1/4” hole is conditioned for 4 hours at 500 gpm flow rate. Time taken to trip in and trip out the conditioning BHA is 6 hours. By default, the WELLCAT software reports temperature versus time and pressure versus time data for the top and end of drillstring. You can request this data at additional depths besides the default. In this case, specify an additional depth point at the shoe of the previous casing, 9,700 ft.


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Chapter 4: Drill

If the bit nozzle data does not display, click the Ocean Current tab, and then return to the Drill String tab.

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Chapter 4: Drill

Run 9 5/8” Casing It takes 30 hours to run in the 9 5/8” casing. Cementing begins right after circulating at bottom for a period of 6 hours at 500 gpm.


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Chapter 4: Drill

Cement 9 5/8” Casing The cement slurry is pumped at 8 bpm and 50° F injection temperature followed by the displacement fluid at 500 gpm. The waiting on cement time is 8 hours. The lead is 14.8 ppg slurry, and 1,000 ft of 15.8 ppg tail slurry is used. 50 bbl of 14.6 ppg lead spacer precedes cement and is pumped at 500 gpm at 50° F inlet temperature.

WELLCAT does not consider the casing to be set in the hole unless the cement has hardened. Therefore, for the cement operation, use the same casing you have been using since the cement is not set at this time.

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Chapter 4: Drill

8 1/2” Hole Section

Drill 8 1/2” Hole

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Run 7” Liner

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Chapter 4: Drill

Cement 7” Liner

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Chapter 4: Drill

6. Calculate Drill Module results.

Calculate results using: - Results > Calculate option - Pressing the F8 keyboard key - Click the Calculate icon - Using the Wizard

The Calculate dialog will display.


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Chapter 4: Drill

A list of all operations defined using the Drilling Operations dialog and tabs is displayed. By default, all operations that have not been calculated since the OK button was pressed on one of the Drilling Operations tabs are selected when the dialog opens. You can select a subset of these operations for calculations by using the Shift and Ctrl keys on your keyboard. If required, you can click Diagnostics... to display engineering data before and after each calculation. Click Calculate to perform calculations for the selected operations. A progress bar indicates the calculation progress for each operation individually. The Calculate dialog box automatically closes when the calculations are complete. You can then view the calculated results, which are available in the Results menu. 7. At the end of the Drill 12 1/4” Hole operation, what is the temperature of the fluid in the annulus? Use Results > Multiple

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Chapter 4: Drill

Operations > Fluid Temperature. Right-click in the plot, and use the Data Selection dialog to select the operation and flow path.

WELLCAT displays the temperature at end of the operation.


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Chapter 4: Drill

8. Does the Number of Trips considered in the analysis change the results much in this example? Compare results using 1 and 4 trips for the Drill 12 1/4” Hole operation. to use Copy Op.

Temperatures are slightly hotter with one trip.

9. There is no circulation in a logging operation. What do you think will happen to the annular fluid temperature when you are not

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Chapter 4: Drill

circulating? Compare the results for the Drill 12 1/4” Hole, Logging 12 1/4” Hole, and Condition 12 1/4” Hole operations.

The temperature during logging is the hottest because there is no circulation.

10. WELLCAT does not have a BOP Test operation type. If you wanted to model a BOP test or shut-in operation, what type of operation would you use? A logging operation because it is the only one that does not involve fluid circulation.


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Chapter 4: Drill

11. If you pump faster during a circulation operation, will it always lower the temperature in the annulus? Analyze the Condition 12 1/ 4” Hole operation while circulating at 500, 600, 650, and 700 gpm.

Circulating at 600gpm has a lower temperature than circulating at 500 gpm.

Interestingly, the temperature at 700 gpm is a bit higher. This suggests that somewhere between 600 and 700 the temperature reverses.

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Chapter 4: Drill

It may be easier to read the data in tabular form.

12. What could be causing this? How does fluid flow change with flow rate? Use the Flow Summary.

Notice there is turbulent flow at 700 gpm.


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Chapter 4: Drill

At 650 gpm, it is all laminar flow.

13. When you review the results for an operation, at what time in the operation do the results represent? Results are presented for the end of the operation.

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Chapter 4: Drill

14. At the end of the Drill 12/14” Hole and the Logging 12 1/4” Hole operations, how far out from the center of the wellbore has the formation temperature increased?


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Chapter 4: Drill

15. Is the ECD in the safe range for all operations?

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Chapter 4: Drill

Drill Input Data Report Use the excerpts from the Results > Reports > Input Drill Data report for operational parameters to use in the exercise.


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Chapter 5

Prod The WELLCAT™ software Prod module is a thermal and pressure simulator. It is used to simulate fluid flow and heat transfer in the wellbore and the surrounding formation during completion, production, stimulation, steam injection, testing, and well servicing operations. It has the capability to model a full transient or steady-state fluid flow and heat transfers solution. Results from the Prod module are available for use during stress analysis inside the Tube and Casing module. Prod is an advanced engineering tool used for predicting: •

Temperatures and pressures for flowing and shut-in well streams.

•

Conditions for casing and tubing stress analysis based on service loads.

•

Temperatures and pressures during forward and reverse circulation operations.

•

Thermo-setting resin and gel treatment behavior.

•

Permafrost thaw radius.

Prod has the following functional features: •

Modeling, in series, of linked production and nonproduction periods, including circulation and injection operations, to build an accurate temperature history of the wellbore

•

Modeling of compositional (black-oil), VLE, and file-defined hydrocarbons as well as water-based and oil-based drilling fluids, synthetic muds, brines, foams, cements, and reactive gel treatment fluids

•

Analysis of multiphase flow using standard industry correlation models (Beggs & Brill; Duns and Ros; Gray, Hagedorn & Brown; Orkiszewski) or mechanistic models (Zhang, Ansari, Kaya)

•

Analysis of gas PVT behavior using standard industry equations-of-state (Benedict-Webb-Rubin, Soave-Redlich-Kwong, Soave-Redlich-Kwong-Starling, and Peng-Robinson)

•

Modeling of steam properties during steam injection using a NIST/ASME model

•

Modeling of temperature and pressure dependence of density and viscosity for water-based and oil-based drilling fluids


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Chapter 5: Prod

•

Consideration of all casing strings and annulus fluids in the thermal analysis, and reporting of results for each pipe and annular fluid in the wellbore

•

Calculation of time-domain variations of fluid pressure and properties in transient analysis

•

Analysis of permafrost thaw and freeze back behavior

•

Modeling of gel-injection operations, with radial tracking of gel front in permeable layers

•

Analysis of coiled tubing-aided well servicing operations

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Chapter 5: Prod

Workflow Overview In this section of the course, you will learn how to use the Prod module. You will define several production operations that occur during the life of the well. You will continue working on the design that was created in the previous chapter. Later in the course, you will use results from the Prod module to create load cases for the casing and tubing strings inside the wellbore. The specific details for each of the fluid flow and heat transfer simulations are entered in the Operations > Operations dialog. This dialog box contains several tabs for you to define the production operation parameters. The tabs available are based on selections made in the Operations dialog. In this exercise, you will create the following operations: • • • • • • • • • • •

Displace to brine Pull workstring, run tubing, and set packer Initial production Shut-in #1 Acid Job Shut-in #2 Produce 1 year Shut-in #3 Post-prod acid job Shut-in #4 Gas lift of depleted zones

After you have defined all the production operations, you will calculate and view the results of the thermal simulations.


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Chapter 5: Prod

Workflow Steps 1. Import 5000_1_13_WELLCAT_Start_Prod.edm.xml. Open the WELLCAT Training Design and activate the Prod module. 2. Use the Default formation properties, with no permeable layers, from 400 to 16,300 ft TVD. What is the Lithology data used for? 3. Create the following operations. Name

Configuration

Operation Type

Fluid

Prior Operation

Displace to Brine

Workstring

Circulation

10.0 ppg CaCl2

Run and Set 7” Tieback (Drill Operation)

Pull ws, run tbg, set pkr

Production Tubing

Shut-In

Initial production

Production Tubing

Production

Shut-in #1

Production Tubing

Shut-in

Acid Job

Production Tubing

Injection

Shut-in #2

Production Tubing

Shut-in

Produce 1 year

Production Tubing

Production

Shut-in #3

Production Tubing

Shut-in

Post-prod acid job

Production Tubing

Injection

Shut-in #4

Production Tubing

Shut-in

Gas lift of depleted zone/(Annulus)

Production Tubing

Gas Lift (Gas Lift)

Displace to brine Produced fluid

Pull ws, run tbg, set pkr Initial production

Acid

Shut-in #1 Acid Job

Produced fluid

Shut-in #2 Produce 1 year

Acid

Shut-in #3 Post-prod acid job

Produced Fluid (Produced Gas)

Undisturbed

Use the data presented in the Results > Reports > Prod Input Data report on page 38. When entering the operational parameters: • In order to update the calculated values, sometimes it is necessary to highlight the value, click the Backspace key, and then click the Tab key to refresh the calculated field. • Although it is not necessary to input the operations on the Operations > Operations dia the order they are

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Chapter 5: Prod

performed, it is easier. In any case, be sure to select the correct Prior Operation on the Operations dialog. • Operations can be dragged into the correct position in the Name list by clicking the left mouse button when an operation is highlighted, moving the cursor to where you want to drop it, then releasing the mouse button. • It is a good practice to calculate results (

) and save (

)data.

• To reduce the time required to create an operation, consider using the Copy Op functionality to create similar operations. When using this functionality, it is important to ensure the copied parameters are edited to correctly reflect the operation details. • Use Operations > Operations to define the operation geometry configuration, select the operation, fluids in the string and/or annulus, the prior operation, and whether you want to use steady-state or transient conditions. • To specify operation details, click Details on the Operations dialog. Use the details tabs to define additional details describing the operation.

Riser Present There is a small check box labeled “Riser Present” which acts as a switch to have a marine riser situated from the seabed to surface. This normally only applies to subsea stack wells or TLP platform wells and, therefore, to semisubmersible operations, and needs to be checked for each operation to which it applies. If checked, an extra tab will be inserted in the Details dialog box for each operation for which it was checked.

4. Calculate Prod results. 5. Compare fluid temperatures for multiple production operations using Results > Multiple Operations > Fluid Temperature or Results > Single Operations > Formation Temperature. to right-click, and use the Data Selection dialog to select the operation and flow path you want to analyze. a) What has happened to the fluid temperature inside the workstring at the end of the Displace to Brine operation?


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Chapter 5: Prod

b) Two days later, at the end of the Pull ws, run tbg, set pkr production operations, what has happened to the fluid temperature inside the tubing? c) Which production operation, Initial Production or Produce 1 year, has the highest flowing wellhead fluid temperature inside the tubing? Why? d) What production temperature would the wellhead elements be required to handle? (The spreadsheet view may present this information in an easier to read format.) e) During the Produce 1 year operation, the fluid inside the tubing is hot. During the one day shut-in operation (Shut-in #3), after producing for one year, is the temperature of the tubing fluid cooling? f) Does the tubing continue to cool during the Post-prod acid job? g) What happens to the fluid temperature inside the tubing during the Shut-in #4 operation? Why? 6. Analyze how the fluid temperature builds up as a function of time during the different production operations. Select Results > Single Operation > Temperature vs. Time. a) How long does it take for the temperature at the top of the tubing to stabilize during production? 7. Review temperatures of all casings/tubing, and/or the fluids inside the casing/tubing and the annulus using Results > Single Operations > Wellbore Temperature. a) At the end of the Produce 1 year operation, what casing/tubing strings are heated above 250° F?

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Chapter 5: Prod

Workflow Solution 1. Use File > Import > Transfer File to import 5000_1_13_WELLCAT_Start_Prod.edm.xml. Activate the Prod module by clicking the Prod icon ( ) on the Product toolbar. You can also select Tools > Select Product > Prod. 2. Use the Default formation properties, with no permeable layers, from 400 to 16,300 ft TVD. The Wellbore > Lithology information is used by the Drill and Prod modules to define the heat transfer characteristics of the formation layers around the wellbore. This spreadsheet can also be used to define permeable layers within the formation, which is used while modeling injection operations in the Prod module. The lithology is the only additional wellbore input that is required before creating production operations. The Formation Properties column has a pull-down list from which you can either select a default lithology (as shown here), or a previously defined lithology. You can also access the Inventories > Formation/Soil Properties inventory to define a new lithology.


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Chapter 5: Prod

3. Specify the following production operations. In this exercise, you will create the following operations. Name

Configuration

Operation Type

Fluid

Prior Operation

Displace to Brine

Workstring

Circulation

10.0 ppg CaCl2

Run and Set 7” Tieback (Drill Operation)

Pull ws, run tbg, set pkr

Production Tubing

Shut-In

Initial production

Production Tubing

Production

Shut-in #1

Production Tubing

Shut-in

Acid Job

Production Tubing

Injection

Shut-in #2

Production Tubing

Shut-in

Produce 1 year

Production Tubing

Production

Shut-in #3

Production Tubing

Shut-in

Post-prod acid job

Production Tubing

Injection

Shut-in #4

Production Tubing

Shut-in

Gas lift of depleted zone/(Annulus)

Production Tubing

Gas Lift (Gas Lift)

Displace to brine Produced fluid

Pull ws, run tbg, set pkr Initial production

Acid

Shut-in #1 Acid Job

Produced fluid

Shut-in #2 Produce 1 year

Acid

Shut-in #3 Post-prod acid job

Produced Fluid (Produced Gas)

Undisturbed

Use the excerpts from the Results > Reports > Prod Input Data report on page 38. When entering the operational parameters: • In order to update the calculated values, sometimes it is necessary to highlight the value, click the Backspace key, and then click the Tab key to refresh the calculated field. • Although it is not necessary to input the operations on the Operations > Operations dia the order they are performed, it is easier. In any case, be sure to select the correct Prior Operation on the Operations dialog. • Operations can be dragged into the correct position in the Name list by clicking the left mouse button when an operation is highlighted, moving the cursor to where you want to drop it, then releasing the mouse button. • It is a good practice to calculate results ( ( )data

5-8


) and save

Chapter 5: Prod

• To reduce the time required to create an operation, consider using the Copy Op functionality to create similar operations. When using this functionality, it is important to ensure the copied parameters are edited to correctly reflect the operation details. • Use Operations > Operations to define the operation geometry configuration, select the operation, fluids in the string and/or annulus, the prior operation, and whether you want to use steady-state or transient conditions. • To specify operation details, click Details on the Operations dialog. Use the details tabs to define additional details describing the operation.

Riser Present There is a small check box labeled “Riser Present” which acts as a switch to have a marine riser situated from the seabed to surface. This normally only applies to subsea stack wells or TLP platform wells and, therefore, to semisubmersible operations, and needs to be checked for each operation to which it applies. If checked, an extra tab will be inserted in the Details dialog box for each operation for which it was checked.


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Chapter 5: Prod

Displace to Brine To create an Operation, enter the name in the Name section. The remaining data on this dialog pertains to the highlighted operation.

Configuration is at the end of the operation.

Most operations are transient. Longer term operations, like production, may be steady-state. If the operation is transient, a prior operation must be selected in the Prior Operation field

5-10

Select the fluid associated with this operation. If the fluid has not been defined, select Inventory from the pull-down list and define the fluid first in the Fluids Inventory.

The Model Permeable Layers option is enabled only for single-phase liquid injection and polymer treatment operations, and the formation was defined as permeable in the Lithology spreadsheet.


Chapter 5: Prod


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Chapter 5: Prod

Pull Workstring, Run Tubing, Set Packer

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Chapter 5: Prod

Pressure can be specified either at the wellhead or at the perforations. This selection is available in the Location pulldown list. This operation, as opposed to the previously discussed displacement job, uses the production tubing. Note the missing Geometry tab, which is not necessary since the production tubing has already been defined.


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Chapter 5: Prod

Initial production

To specify production rates, first select the Input data. In this example, Oil, Gas & Water is selected, so these fields are enabled. GOR is disabled but calculated. The other possible selections are Oil, GOR & Water or GOR, Gas & Water.

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Chapter 5: Prod

Shut-in #1


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Chapter 5: Prod

For the first shut-in operation after initial production, specify a 14,000 psi pressure at the perforations at 17,150 ft. The well is shut-in for a duration of one day.

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Chapter 5: Prod

Acid Job

For the acid job after shut-in, specify a 14,700 psi flowing pressure at the perforations. The acid is injected at an inlet temperature of 45° F and at a rate of 84 gpm. The time of injection is eight hours.


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Chapter 5: Prod

Shut-in #2

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Chapter 5: Prod

After the acid job, the well is shutin for one day with a 14,000 psi pressure at perforations.


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Chapter 5: Prod

Produce 1 year

The long-term production operation is modeled for a period of one year. The production flow rate is 5,000 bbl/day oil and 25 MMscf/day gas. Use the default geothermal temperature at perforations as the inlet temperature. The bottomhole flowing pressure is 13,500 psi. Use the Hagedorn & Brown multiphase correlation and the SRK gas model. Refer to the online help for suggestions when each model should be considered.

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Chapter 5: Prod

Shut-in #3


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Chapter 5: Prod

After one year of production model a one day shut-in operation with a 14,000 psi static pressure at perforations.

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Chapter 5: Prod

Post-prod acid job

The next operation is a postproduction acid job with acid injected at a rate of 84 gpm for eight hours with an injection temperature of 45° F. The bottomhole flowing pressure at the perforations is 14,700 psi


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Chapter 5: Prod

Shut-in #4

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Chapter 5: Prod

Model another shut-in operation for two days, and specify the details shown here.


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Chapter 5: Prod

Gas lift of depleted zones

Model a two day gas lift operation. The production flow rate during gas lift is 2000 bbl/day oil, 0.1 MMscf/day gas, and 120 bbl/day water. The bottomhole flowing pressure is 3,400 psi. Specify default geothermal inlet temperature. Use the Hagedorn & Brown model for multiphase correlations.

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Chapter 5: Prod

Specify an annular gas injection rate of 2 MMscf/day and an injection pressure and temperature of 2,500 psi and 100° F respectively. The gas lift valve is set at 16,000 ft MD.

4. Calculate Prod Results

Calculate results using: - Results > Calculate option - Pressing the F8 keyboard key - Click the Calculate icon - Using the Wizard


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Chapter 5: Prod

Click Calculate to calculate results for the selected operations and the operations with results that are required to obtain the Initial Condition Temperature profiles for the selected operations.

Operations that must be recalculated due to data change will be highlighted.

Click Diagnostics... to display engineering data before and after each calculation. Use the Diagnostics... dialog to specify the files you want displayed during the load and operation calculations. The Diagnostics dialog box looks the same for each module in the WELLCAT software.

5. Compare fluid temperatures for multiple production operations using Results > Multiple Operations > Fluid Temperature or Results > Single Operations > Formation Temperature. to right-click, and use the Data Selection dialog to select the operation and flow path you want to analyze.

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Chapter 5: Prod

a) What has happened to the fluid temperature inside the tubing at the end of the Displace to Brine operation?

Circulating cool brine into the well during the displacement process results in a cooling of the fluid temperatures in the string.

Using Results > Multiple Operations > Wellbore Temperatures, you can see that circulating cool brine into the well during the displacement process results in a cooling of the tubing string.


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Chapter 5: Prod

b) Two days later, at the end of the Pull ws, run tbg, set pkr production operations, what has happened to the fluid temperature inside the tubing?

Two days later, when the tubing is set in place, the temperature has warmed, and is nearly identical to the Undisturbed profile.

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Chapter 5: Prod

c) Which production operation, Initial Production or Produce 1 year, has the highest flowing wellhead fluid temperature inside the tubing? Why? The long-term production (Produce 1 year) generates a flowing wellhead temperature 100° F hotter than the two-day production test (Initial Production). Both the long duration and the high production rate cause this higher temperature.


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Chapter 5: Prod

d) What production temperature would the wellhead elements be required to handle? (The spreadsheet view may present this information in an easier to read format.) Wellhead elements should handle these temperatures for production operations.

e) During the Produce 1 year operation, the fluid inside the tubing is hot. During the one day shut-in operation (Shut-in #3), after producing for one year, is the temperature of the tubing fluid cooling? Yes, the fluid inside the tubing cools significantly during this one day shut-in.

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Chapter 5: Prod

f) Does the tubing continue to cool during the Post-prod acid job? Yes, the injection of cool fluid continues to cool the tubing. Below approximately 10,800ft it becomes cooler than the Undisturbed temperature.


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Chapter 5: Prod

g) What happens to the fluid temperature inside the tubing during the Shut-in #4 operation? Why? The Shut-in #4 curve shows that, at the end of the acid job, instead of continuing to cool off towards the Undisturbed profile, the wellbore heats back up again. This result is caused by the cumulative effect of radial thermal conduction during one year of production. As a result, the formation surrounding the wellbore is much hotter than undisturbed even after an acid job.

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Chapter 5: Prod

WELLCAT assumes undisturbed temperature 50 ft from the wellbore center. Notice in the following plot that at the end of the Produce 1 year operation the temperature rises closer to the wellbore center due to the cumulative effect of radial thermal conduction during one year of production.

Use the Input/Single Result Wizard List to scroll through the operations as you view the formation temperatures. Notice that farther from the wellbore the temperature change is between the Produce 1 year and Shut-in #4 operations is not significant.

6. Analyze how the fluid temperature builds up as a function of time during the different production operations. Select Results > Single Operation > Temperature vs. Time.


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Chapter 5: Prod

a) How long does it take for the temperature at the top of the tubing to stabilize during production? Even though the produced fluid heats up quickly, the equilibrium of the flowing temperature is not reached for months. This result can be useful for a production test if your equipment has temperature limitations. You may need to limit the duration of flow to keep the temperature at the mudline or surface below a given value.

7. Review temperatures of all casings/tubing, and/or the fluids inside the casing/tubing and the annulus using Results > Single Operations > Wellbore Temperature. a) At the end of the Produce 1 year operation, what casing/tubing strings are heated above 250° F? Below the mudline, all the casing/tubing strings, except for the surface casing, are heated above 250° F at the end of the one-year production. This large increase in temperature can cause significant thermal axial growth and potential buckling problems. If the annular spaces between casings have no pressure outlet and are filled, this increase in temperature can also cause thermal expansion of the trapped fluid, thereby resulting in severe pressure increases in each of the annuli.

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Chapter 5: Prod

The MultiString module calculates annular pressure build-up in trapped annuli based on Prod thermal simulations.


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Chapter 5: Prod

Prod Input Data Report This section shows a detailed report generated by the WELLCAT software that contains information for the input data required for defining all the production operations in this exercise. Input data that needs to be entered in both the Wellbore menu and the Operations menu is provided.

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Chapter 6

Casing The WELLCAT™ Casing module is used to analyze casing loads, design integrity, and buckling behavior under complex mechanical, fluid pressure, and thermal loading conditions. It has standard and automatic load cases that can be linked to Drill or Prod thermal analysis. The Casing module is an advanced engineering tool used for: •

Comprehensive casing, liner, and tie-back design and analysis.

•

Installation and service load analysis.

•

Multi-string load transfer analysis.

•

Buckling stability and post-buckling analysis.

Casing module has the following functional features: •

Determination of running, installation, and service loads and stresses from standard or automatically generated -defined load cases

•

Determination of accurate loads, stresses, and buckling solutions for both vertical and directional wells, with or without friction

•

Consideration of all mechanical, fluid pressure, and thermal loading mechanisms

•

Specification of separate design factors for pipe body and connection

•

Determination of burst, collapse, axial, and triaxial safety factors, with burst and axial safety factors based on lesser pipe body or connection rating

•

Ability to include centralizers in the stress model to more accurately predict forces

•

Accommodation of -specified yield anisotropy for CRA or composite materials applications

•

Ability to specify ISO connection ratings and view triaxial design factors for the ISO connections

•

Accommodation of -specified temperature-dependent yield strength and -specified minimum wall thickness (API default)


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Chapter 6: Casing

Workflow Overview In this section of the course, you will learn how to use the Casing module. You will define multiple load cases to model the stresses acting on the 9 5/8” Protective Casing during the life of the well. You will continue working on the design created in the previous chapter. You will use results from the Prod module to create load cases for the casing and tubing strings inside the wellbore. The specific details for each of the loads are entered using the Loads > Loads dialog. This dialog box contains several tabs for you to define the load parameters. The tabs available are based on selections made in the Loads dialog. In this exercise, you will create the following loads: • • • • • • •

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Green Cement Test Lost Returns with Water Gas Kick Overpull Mud Drop Due to Lost Returns Drill Ahead Produce 1 Year


Chapter 6: Casing

Workflow Steps Note: Refer to “Casing Input Data Report” on page 31 for data and analysis parameters for use in the exercise. 1. Import 5000_1_13_WELLCAT_Start_Casing.edm.xml. Open the WELLCAT Training Design and activate the Casing module. 2. In this workflow, we are analyzing the 9 5/8” Protective Casing. How do you select a string for analysis? 3. What is the Wellbore > Dogleg Severity Overrides spreadsheet and the Max DLS column in the Wellbore > Wellpath Editor used for? 4. To for tortuosity in the wellbore, use the Wellbore > Dogleg Severity Overrides spreadsheet to specify a 2°/100ft dogleg override through the entire wellbore. Then use Wellbore > Wellpath Editor to specify a maximum dogleg severity of 4°/100ft between 2,100 - 3,500 ft MD, and 14,500 - 15,000 ft MD. a) What dogleg values does the software use to calculate bending stresses? b) Using the Results > Dogleg Profile what dogleg severity will be used in the calculating of bending stresses? 5. Use the Wellbore > Cementing and Landing dialog box to specify the cementing data for the casing. Use defaults for all data except the following: •

Lead Slurry: 14.8 ppg slurry

•

Tail Slurry: 1000ft of 15.8 ppg slurry

•

Displacement Fluid: 14.5 ppg OBM

6. How do you apply an upward force to the casing at the surface before landing the string in the wellhead so that only the part of the string above the TOC experiences the increase in tension? 7. What are the minimum acceptable design factors for the pipe body and connections used for all load analysis?


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8. Include in the analysis the effect of temperature on minimum yield strength, and the effect of frictional with the casing due to buckling and hole curvature. Use the default value (0.3) for friction. 9. What temperature deration schedule is used? 10. What do “initial conditions” represent? 11. Where do the default initial conditions come from? 12. Using the default values, what are the annular fluid densities for the initial conditions? 13. For this workflow, we want to use the Cement 9 5/8” Casing operation as the initial conditions for both temperature and density profiles, in the string and annulus, for all of the loads. 14. After changing the temperature and density profiles, how have the fluid densities in the annulus changed? 15. Create the Overpull load using the data in section “Casing Input Data Report” on page 31. 16. Create the Green Cement Test load using the data in section “Casing Input Data Report” on page 31. a) What external pressure profile is used for Green Cement Test load types and why? 17. Create the Gas Kick load using the data in section “Casing Input Data Report” on page 31. What is the Fracture Margin of Error? 18. Create the Lost Returns with Water load using the data in section “Casing Input Data Report” on page 31. a) Where do the temperature and pressure profiles for this load come from? b) Is this a burst or collapse load? 19. Create the Drill Ahead load using the data in section “Casing Input Data Report” on page 31. a) Where do Drill Link Type loads retrieve temperature and pressure profiles from?

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Chapter 6: Casing

20. Create the Mud Drop due to Lost Returns load using the data in section “Casing Input Data Report” on page 31. a) Why do we use the 17.5ppg OBM as the Fluid Inside Casing? b) Is this a burst or collapse load? 21. Create the Produce 1 Year load using the data in section “Casing Input Data Report” on page 31. a) Why is the 17.5 ppg WBM used for the Internal Pressure Profile inside the 9 5/8” casing? 22. Calculate results. 23. Refer to the Results > Multiple Loads > Design Limits Plot. What loads appear to be failing? 24. If all loads were located in the very middle of the Design Limits Plot, what would you think? 25. Loads appearing to fail in the Design Limits Plot should be further investigated. Use the Results > Summaries > Minimum Safety Factor table to determine what loads are not meeting the design factor. 26. Which loads have the most total length change? 27. For the Produce 1 Year load, how much of the casing is buckled? 28. How much torque is acting on the casing above the TOC during the Produce 1 Year operation? What is the dogleg above the TOC? 29. What are some possible solutions to the issues we have seen? 30. Change grade of the 9 5/8” casing to Q-125, and include an LTC Q125 connection as well. 31. Calculate the results, and review the Design Limits Plot. Does it indicate areas of concern? 32. To further investigate the results displayed on the Design Limits Plot, use the Results > Summaries > Minimum Safety Factor table. Is the connection failing? 33. Change the 9 5/8” connection to Vam.


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Chapter 6: Casing

34. Calculate the results, and review the Minimum Safety Factors table. Are issues with the connection resolved?

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Chapter 6: Casing

Workflow Solution Note: Refer to “Casing Input Data Report” on page 31 for data and analysis parameters for use in the exercise. 1. Use File > Import > Transfer File to import 5000_1_13_WELLCAT_Start_Casing.edm.xml. Activate the Casing module by clicking the Casing icon ( ) on the Product toolbar. You can also select Tools > Select Product > Casing. 2. In this workflow, we are analyzing the 9 5/8” Protective Casing. How do you select a string for analysis? Select the 9 5/8” Protective Casing using the Current String drop-down, as shown below. Alternatively, select Wellbore > Current String > 9 5/8” Protective Casing.

3. What is the Wellbore > Dogleg Severity Overrides spreadsheet and the Max DLS column in the Wellbore > Wellpath Editor used for? Wellbore > Dogleg Severity Overrides spreadsheet and the Max DLS column in the Wellbore > Wellpath Editor are used to override the smoothness by adding tortuosity to a planned well path for use in bending stress calculations. Dogleg overrides should not be applied to actual wellpath data. 4. To for tortuosity in the wellbore, use the Wellbore > Dogleg Severity Overrides spreadsheet to specify a 2°/100ft dogleg override through the entire wellbore. Then use Wellbore >


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Chapter 6: Casing

Wellpath Editor to specify a maximum dogleg severity of 4°/100ft between 2,100 - 3,500 ft MD, and 14,500 - 15,000 ft MD.

a) What dogleg values does the software use to calculate bending stresses? WELLCAT calculates the bending stresses based on the maximum specified dogleg severity on either the Dogleg Severity Overrides spreadsheet or the Wellpath Editor. b) Using the Results > Dogleg Profile what dogleg severity will be used in the calculating of bending stresses?

A 2º/100 ft dogleg, as specified on the Dogleg Severity Overrides spreadsheet, is used throughout much of the wellbore. 4º/100ft is used in the two intervals specified using the Wellpath Editor.

5. Specify the cementing data for the casing. Use defaults for all data except the following:

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•

Lead Slurry: 14.8 ppg slurry

•

Tail Slurry: 1000ft of 15.8 ppg slurry


Chapter 6: Casing

•

Displacement Fluid: 14.5 ppg OBM

Select the desired fluid from the drop-down lists. Only fluids in the Inventories > Fluid Inventory are displayed. If the fluid you want to use is not in the list, you must add it to the Fluid Inventory.

6. How do you apply an upward force to the casing at the surface before landing the string in the wellhead so that only the part of the string above the TOC experiences the increase in tension? On the Wellbore > Cementing and Landing > Primary Cementing and Landing tab, click the Pickup Force radio button and enter the force. Use Applied Surface Pressure if the surface pressure is applied during the WOC period. 7. What are the minimum acceptable design factors for the pipe body and connections used for all load analysis? Use Loads > Design Parameters to define the design factors. In this exercise, the following are used.


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Chapter 6: Casing

8. Include in the analysis the effect of temperature on minimum yield strength, and the effect of frictional with the casing due to buckling and hole curvature. Use the default value (0.3) for friction. Use Wellbore > Design Parameters > Analysis Options as indicated below.

9. What temperature deration schedule is used? The Inventories > Temperature Deration schedule is used.

10. What do “initial conditions” represent? Loads > Initial Conditions represent the internal and external pressure profiles, and the temperature profile for the load after the casing/tubing is landed and cemented.

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Chapter 6: Casing

11. Where do the default initial conditions come from?

The default values are derived from data on the Wellbore > Cementing and Landing dialog and from Wellbore > Undisturbed Temperature dialog, and represent the conditions immediately after the displacement of the cement.

12. Using the default values, what are the annular fluid densities for the initial conditions? Use Loads > Initial Conditions > Annulus.

Default annular fluid densities: Mud Lead Cement Tail Cement

13. For this workflow, we want to use the Cement 9 5/8” Casing operation as the initial conditions for both temperature and density


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Chapter 6: Casing

profiles, in the string and annulus, for all of the loads. Use the Fill button to do this.

Check the Fill button.

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Chapter 6: Casing

14. After changing the temperature and density profiles, how have the fluid densities in the annulus changed?

The densities have increased due to hydrostatic pressure.

15. Create the Overpull load using the data in section “Casing Input Data Report” on page 31.


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Chapter 6: Casing

16. Create the Green Cement Test load using the data in section “Casing Input Data Report” on page 31.

a) What external pressure profile is used for Green Cement Test load types and why? The external pressure profile for the Green Cement Test is displacement fluid above the TOC, lead cement, and tail cement gradients. By definition, a Green Cement Test is done while the cement is still in the fluid state (green), so the external pressure profiles should be due to fluids in annulus at the time, including cements. 17. Create the Gas Kick load using the data in section “Casing Input Data Report” on page 31. What is the Fracture Margin of Error? It is the incremental amount above the fracture gradient that will be allowed at the shoe. Using a margin of error can result in a more conservative analysis since the internal pressure profile needs to be

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Chapter 6: Casing

greater to exceed the fracture gradient plus the margin of error at the shoe.


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Chapter 6: Casing

18. Create the Lost Returns with Water load using the data in section “Casing Input Data Report” on page 31.

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Chapter 6: Casing

a) Where do the temperature and pressure profiles for this load come from? This load is a “hybrid” type load, which means it uses temperature and pressure predictions from another casing load that is linked to a Drill or Prod operation. In this specific load, the predictions are coming from the Initial Conditions load which is linked to the Cement 9 5/8” Casing Drill operation. b) Is this a burst or collapse load? This is a burst load


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Chapter 6: Casing

19. Create the Drill Ahead load using the data in section “Casing Input Data Report” on page 31.

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Chapter 6: Casing

a) Where do Drill Link Type loads retrieve temperature and pressure profiles from? A predefined Drill operation. 20. Create the Mud Drop due to Lost Returns load using the data in section “Casing Input Data Report” on page 31.


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Chapter 6: Casing

a) Why do we use the 17.5ppg OBM as the Fluid Inside Casing? Because it is the fluid used to drill the next hole section and is the fluid in the hole during lost circulation. b) Is this a burst or collapse load? This is a collapse load. 21. Create the Produce 1 Year load using the data in section “Casing Input Data Report” on page 31.

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Chapter 6: Casing

a) Why is the 17.5 ppg WBM used for the Internal Pressure Profile inside the 9 5/8” casing? Refer to the Wellbore > Casing and Tubing Configuration spreadsheet. Note that the fluid


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Chapter 6: Casing

inside the 9 5/8” casing is the same fluid in the annulus of the 7” Tieback.

22. Calculate results. Click

to calculate results.

Blue highlighted loads must be calculated because there has been a data change since the load was last calculated.

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Chapter 6: Casing

23. Refer to the Results > Multiple Loads > Design Limits Plot. What loads appear to be failing? Three loads, Lost Returns with Water, Gas Kick, and Produce 1 Year.

24. If all loads were located in the very middle of the Design Limits Plot, what would you think? If all loads are in the middle, perhaps the string is over designed and a lighter pipe or different grade may work. 25. Loads appearing to fail in the Design Limits Plot should be further investigated. Use the Results > Summaries > Minimum Safety Factor table to determine what loads are not meeting the design factor. The Minimum Safety Factor table indicates the triaxial absolute safety factor is less than the triaxial design factor for the Lost Returns with Water and Gas Kick loads, and the burst absolute


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Chapter 6: Casing

safety factor is less than the burst design factor for the Lost Returns with Water load.

The asterisk (*) indicates the Absolute Safety Factor is less than the Design factor. Look at the codes at the bottom of the table to determine what they stand for.

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Chapter 6: Casing

26. Which loads have the most total length change? Use Results > Multiple Loads > Length Change Bar Chart. Total length change is zero for loads after the cement has set. Total length change is only non-zero when there is displacement at the surface due to pick-up, or slack-off after cement is set.

27. For the Produce 1 Year load, how much of the casing is buckled? Use Results > Summaries > Movement. Buckled length


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Chapter 6: Casing

28. How much torque is acting on the casing above the TOC during the Produce 1 Year operation? Use Results > Summaries > Casing Load.

Torque acting above the TOC. The torque and dogleg above the TOC is due to buckling.

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Chapter 6: Casing

29. What is a possible solutions to the issues we have seen? Apply a pick-up force. Refer to Results > Summaries > Casing Load.

Notice the advised pickup to prevent buckling.

30. Change grade of the 9 5/8” casing to Q-125, and include an LTC Q125 connection as well.


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Chapter 6: Casing

31. Calculate the results, and review the Design Limits Plot. Does it indicate areas of concern? The Lost Returns with Water load exceeds the triaxial design limit of the connection.

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Chapter 6: Casing

32. To further investigate the results displayed on the Design Limits Plot, use the Results > Summaries > Minimum Safety Factor table. Is the connection failing? Notice the asterisk indicating the design factors are not met.

33. Change the 9 5/8” connection.

Select Vam from the list. If Vam is not in the list, click Inventories and select the Q125 Vam connection.


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Chapter 6: Casing

34. Calculate the results, and review the Minimum Safety Factors table. Are issues with the connection resolved? No. Notice the asterisks, and the C flag indicating issue is in connection..

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Chapter 6: Casing

Casing Input Data Report This section shows a detailed report generated by the WELLCAT software that contains information for the input data required for defining loads for all the casing strings inside the wellbore in this exercise. Input data that needs to be entered in the Wellbore menu and the Loads menu is provided.


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Chapter 7

Tube The WELLCAT™ software Tube module is used to analyze tubing loads, design integrity, and buckling behavior under complex mechanical, fluid pressure, and thermal loading conditions. It has standard and automatic load cases which may be linked to Prod thermal analysis. The Tube module is an advanced engineering tool used for: •

Comprehensive tubing design and analysis.

•

Modeling installation and service loads.

•

Tubing movement analysis.

•

Modeling complex completions.

•

Buckling analysis.

•

Analyzing packer loads.

•

Modeling CRA tubulars with yield anisotropy.

Tube module has the following functional features: •

Determination of installation and service loads and stresses from standard or automatically generated, -defined load cases, including production, injection, shut-in, tubing leak, pump-in to kill, rod pump, pressure test, fracture screen-out, full evacuation, overpull during installation, and so on

•

Determination of accurate loads, stresses, and buckling solutions for both vertical and directional wells, with or without friction

•

Capability to model multiple mechanical, hydraulic, or hydrostatic-set packers set in a -defined setting sequence

•

Capability to model dual-completion designs

•

Specifications of latch down and sliding tubing-packer seal assemblies, with -specified up/down displacement and no-go constraints

•

Consideration of all mechanical, fluid pressure, and thermal loading mechanisms for all load cases


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Chapter 7: Tube

•

Specification of separate design factors for pipe body and connection

•

Determination of burst, collapse, axial, and triaxial safety factors, with burst and axial safety factors based on lesser of pipe body or connection ratings

•

Accommodation of -specified yield anisotropy for CRA or composite materials applications

•

Ability to specify ISO connection ratings and view triaxial design factors for the ISO connections

•

Accommodation of -specified temperature-dependent yield strength and -specified minimum wall thickness (API default)

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Chapter 7: Tube

Workflow Overview In this section of the course, you will learn how to use the Tube module. Continuing with the design used in previous workflows, you will define multiple loads to model the stresses acting on the 3 1/2” tubing during the life of the well. Results from the Prod module will be used to create load cases for the tubing. The specific details for each of the loads are entered using the Loads > Loads dialog. This dialog box contains several tabs for you to define the load parameters. The tabs available are based on selections made in the Loads dialog. In this exercise, you will create the following loads: • • • • • • • •

Overpull while running in hole Pressure Test Steady State Production Production Shut In Tubing Leak Full Evacuation 1 Year Production Acid Job


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Chapter 7: Tube

Workflow Steps 1. Use File > Import > Transfer File to import 5000_1_13_WELLCAT_Start_Tube.edm.xml. Activate the Tube module. 2. Select the 3 1/2” Production Tubing for analysis. 3. How would you specify annular restrictions, such as gravel pack or scab liner, that may inhibit buckling? 4. What is the data in Wellbore > Annulus Contents used for, and where does it default from? 5. Review the design parameters. 6. Indicate that you want to investigate whether two tools can freely through the tubing, and if not, what the required force would be. Tool dimensions: •

2 5/8” OD, 30 feet long

•


7. Specify the initial conditions (temperature and pressure) when the tubing was landed. Use the Prod operation Pull ws, run tbg, set pkr. 8. Create a Latched Permanent Packer.

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•

Name: Latched Permanent Packer

•

Type: Packer

•

Running String: Production Tubing

•

Packer Depth: 17,000 ft MD

•

Set hydraulically with initial set pressure of 1500 psi

•

Plug Depth = 17,000 ft

•

Seal bore is present

•

Packer Bore ID = 3 1/2”


Chapter 7: Tube

•

Use the operating envelope in 5000_1_13_WELLCAT_Packer_Envelope.txt.

9. Create the Overpull while running in hole load. What does this load model? •

Type: Overpull

•

Running Fluid: 10.0 ppg CaCl2

•

Overpull force: 20,000 lbf

10. Create the Pressure Test load. What does this load model? What temperatures are used? •

Type: Pressure Test

•

Pump Pressure: 9500 psi

•

Fluid Inside the Tubing: 10.0 ppg CaCl2

•

Annular wellhead pressure: as calculated

11. Create the Steady State Production (t) load. What does this load model? Steady State Production is a load with internal thermal simulations. It performs a simple thermal calculation using a part of the Prod module engineering algorithms that is incorporated into the Tube module. This load simulates the pressure and temperature profile due to the production operations. Most of the time, it is a burst load. It is also a thermal load as the produced fluids heat up the tubing causing growth. •

Type: Steady State Production

•

Pressure: 13,500 psi at the perforations

•

Perforation Depth: 17,150 ft MD

•

Produced Fluid: Produced Fluid

•

Oil Production Rate: 5,000 bbl/D

•

Gas Production Rate: 25 MMscf/day

•

Water Production Rate: 0 bbl/D


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Chapter 7: Tube

12. Create the Production Shut In load. What does this load model? What temperatures, densities, and external conditions are used? •

Type: Shut-In

•


•

Perforation Depth: 17150 ft MD

•

Link the load to the Steady State Production (t) operation

•

Fluid density inside tubing: Use Tubing Density From Operation or Load

13. Create the Tubing Leak load. What does this load model? •

Type: Tubing Leak

•

Operation or Load: Production Shut-In

14. Create the Full Evacuation load. What does this load model? What temperatures are used? •

Type: Tubing Evacuation

•

Operation or Load: Initial Conditions

15. Create the 1 Year Production load. What does this load model? What temperatures are used? •

Type: Prod Link

•

Operation: Produce 1 year

16. Create the Acid Job load. What does this load model? What temperatures are used? •

Type: Prod Link

•

Operation: Acid Job

17. Calculate results. 18. Review the internal, external, and differential pressures for the following loads: Initial Conditions, Steady State Production (t), Full Evacuation, Pressure Test, and Tubing Leak.

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Chapter 7: Tube

a) What is the internal pressures for the Full Evacuation load? b) Which loads are burst and which are collapse? c) What is the external pressure profile for all those loads? 19. View Results > Multiple Loads > Burst Safety Factor, and Results > Multiple Loads > Differential Pressure for all defined tubing loads in two horizontal windows. a) Based on the Differential Pressure plot, which load(s) is driving the burst design? b) Based on the Differential Pressure plot, which load(s) is driving the collapse design? 20. Replace the Differential Pressure plot with the Results > Multiple Loads > Collapse Safety Factor plot. Do the plots suggest your design is acceptable in of burst and collapse? 21. View Results > Multiple Loads > Axial Safety Factor, and Results > Multiple Loads > Axial Loads for all defined tubing loads in two horizontal windows. Based on these plots, is the axial design criteria met? 22. Using the Results > Multiple Loads > Design Limit plot, which loads do not appear to meet the triaxial design criteria? 23. Using the Results > Multiple Loads > Triaxial Safety Factor plot, which loads do not appear to meet the triaxial design criteria? 24. Refer to Results > Summaries > Minimum Safety Factor. a) Which loads fail triaxial design? b) Why is the Pressure Test load not showing as failing the triaxial design criteria on this table? 25. Investigate tubing movement for the 1 Year Production operation. Use Results > Summaries > Movement. a) Why does the sum of all the movements equal zero? b) Is there a buckling issue?


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Chapter 7: Tube

26. What force is required to prevent buckling for the 1 Year Production load? 27. To begin to solve buckling issues, allow 18 ft downward tubing movement with a “nogo”. 28. Calculate results. What is the total tubing movement now for the 1 Year Production load? 29. For the 1 Year Production load, what force will be required to a tool, and how long can the tool be? 30. Are any loads outside the packer operating envelope? 31. Review Results > Single Load > Packer Schematic. The packer Schematic displays a schematic for each of the packers defined in the string along with important packer forces computed as part of the analysis. 32. Review the packer loads for all loads. Use Results > Multiple Loads > Packer Loads. Refer to the online help for a description of the information displayed.

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Chapter 7: Tube

Workflow Solution 1. Use File > Import > Transfer File to import 5000_1_13_WELLCAT_Start_Tube.edm.xml. Activate the Tube module by clicking the Tube icon ( ) on the Product toolbar. You can also select Tools > Select Product > Tube. 2. Select the 3 1/2” Production Tubing for analysis. Use the Current String selection list.

3. How would you specify annular restrictions, such as gravel pack or scab liner, that may inhibit buckling? Use Wellbore > Buckling Restrictions to model special annular clearance restrictions that may exist in a wellbore. The onset and extent of buckling depend significantly on the annular restrictions between the production tubing and the casing. Restriction ID is between the casing and the tubing. It should be larger than the tubing outside diameter, but smaller than the casing inside diameter.

4. What is the data in Wellbore > Annulus Contents used for, and where does it default from? The Annulus Contents spreadsheet can be used to specify multiple fluids in the tubing annulus. The default value is the tubing annular fluid specified in the Wellbore > Casing and Tubing Configuration. Data from this spreadsheet is used to define the default initial conditions for the production tubing. You can add multiple annular fluids, but at least one of the fluids must be the same as the fluid specified on the Casing and Tubing Configuration spreadsheet. If gas is specified, to alleviate


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Chapter 7: Tube

annular pressure that builds up during production operations, it must be the first fluid in the list. Select the fluid you want to use from the drop-down. If the fluid does not appear, define it in the Inventories > Fluids first.

5. Review the design parameters. Use Loads > Design Parameters. 6. Indicate that you want to investigate whether two tools can freely through the tubing, and if not, what the required force would be. Tool dimensions: •


•


Use Loads > Tool age. This dialog is used to specify tool geometry. For each load, the Tube module will compute the maximum tool length that will through the tubing in the highest dogleg caused by wellbore deviation and buckling. If the tool length is greater than the length that will freely, the software will report the force required to push or pull the tool through the dogleg. The bending stiffness of the tool is assumed to be that of a solid cylinder.

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Chapter 7: Tube

7. Specify the initial conditions (temperature and pressure) when the tubing was landed. Use the Prod operation Pull ws, run tbg, set pkr. Use Loads > Initial Conditions.

Notice the default Data Source is Annulus Contents and Undisturbed Temperatures. Since we have a Prod operation for running the tubing, we will use that instead. Use this operation for inside the tubing and in the annulus.


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Chapter 7: Tube

8. Create a Latched Permanent Packer. Use Wellbore > Packers. Each packer must have a unique depth within the interval delimited by the hanger depth and the tubing base.

Use the Seal Bore Present area to define a piston area for the seal assembly over which a differential pressure can act on the tubing. If this box is not checked, the tubing is assumed to be integral to the packer and latched with no piston effect. The packer bore ID will affect axial force distribution in the tubing.

Use Axial Load Change After Packer Set to specify a pickup or slackoff, at the surface, after the packer is set.

Check the Seal Movement Allowed box to allow for upward or downward tubing movement. A Nogo can be present either way. If the box is not checked, the tubing cannot move and the packer is assumed fixed.

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Chapter 7: Tube

The Operating Envelope tab allows you to specify the packer operating envelope based on vendor specifications. Packers are rated in of annular pressure differential across the packer and load transfer from the tubing to the packer. Packer ratings should be entered in clockwise, or counter-clockwise order. The WELLCAT software will connect the first and last points.

•

Name: Latched Permanent Packer

•

Type: Packer

•

Running String: Production Tubing

•

Packer Depth: 17,000 ft MD

•

Set hydraulically with initial set pressure of 1500 psi

•

Plug Depth = 17,000 ft

•

Seal bore is present

•

Packer Bore ID = 3 1/2”

•

Use the operating envelope in 5000_1_13_WELLCAT_Packer_Envelope.txt.

9. Create the Overpull while running in hole load. What does this load model? Use Loads > Loads.This load simulates tension in the


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Chapter 7: Tube

tubing due to its own buoyed weight plus additional pickup force applied to unset the packer or to free stuck tubing.

•

Type: Overpull

•

Running Fluid: 10.0 ppg CaCl2

•

Overpull force: 20,000 lbf

10. Create the Pressure Test load. What does this load model? What temperatures are used? This load models a tubing pressure test with pressure applied at the surface. The temperatures specified on the Initial Conditions dialog are used as the temperature profile for the load case.

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•

Type: Pressure Test

•

Pump Pressure: 9500 psi

•

Fluid Inside the Tubing: 10.0 ppg CaCl2


Chapter 7: Tube

•

Annular wellhead pressure: 0 psi

11. Create the Steady State Production (t) load. What does this load model? Steady State Production is a load with internal thermal simulations. It performs a simple thermal calculation using a part of the Prod module engineering algorithms that is incorporated into the Tube module. This load simulates the pressure and temperature profile due to the production operations. Most of the time, it is a burst load. It is also a thermal load as the produced fluids heat up the tubing causing growth. •

Type: Steady State Production

•



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Chapter 7: Tube

•

Perforation Depth: 17,150 ft MD

•

Produced Fluid: Produced Fluid

•

Oil Production Rate: 5,000 bbl/D

•

Gas Production Rate: 25 MMscf/day

•

Water Production Rate: 0 bbl/D

Select the type of hydrocarbon being produced. The fluids in the list must be defined on the Inventories > Fluids > Standard Hydrocarbon tab.

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Chapter 7: Tube

12. Create the Production Shut In load. What does this load model? What temperatures, densities, and external conditions are used? This type of load retrieves temperature and pressure predictions from a previously defined Prod operation or a previously defined Tube load with internal thermal simulations. This load should be linked to another load or production operation. The load models shut-in. If this is a long-term shut-in, temperatures are set to undisturbed. If gas is in the tubing during the shut-in, gas gravity can be entered and this will override the internal densities from the production case. Note that if gas gravity is not used, the calculated internal pressures may be slightly inaccurate for compressible fluids because the internal density is based on production temperatures and pressures.

Select the operation or load that you want to use for the temperature profiles.

Choose how the fluid density inside the tubing will be calculated. In this example, we are getting the density from the load.

•

Type: Shut-In

•



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Chapter 7: Tube

•

Perforation Depth: 17150 ft MD

•

Link the load to the Steady State Production (t) operation

•

Fluid density inside tubing: Use Tubing Density From Operation or Load

13. Create the Tubing Leak load. What does this load model? This load case recalls all of the load conditions from the prior case (usually a production case), and applies the tubing pressure on the annulus at the surface, that can result in high-collapse loads near the packer (particularly if a kill weight packer fluid is used). The Operation or Load drop-down list box has the names of all loads or operations defined for the current string that can be linked to other loads. Selecting one of these items allows the code to use the temperature density and pressure profiles from the item as final conditions for the current load case.

•

Type: Tubing Leak

•

Operation or Load: Production Shut-In

14. Create the Full Evacuation load. What does this load model? What temperatures are used? This load simulates air inside the tubing with no surface pressure, and the “packer fluid” as the outside

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Chapter 7: Tube

pressure. Temperatures are assumed to be undisturbed unless a prior case is specified.

•

Type: Tubing Evacuation

•

Operation or Load: Initial Conditions

15. Create the 1 Year Production load. What does this load model? What temperatures are used? This load case is used to model the


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Chapter 7: Tube

current string with the temperature profiles and pressure and additional data imported from a Prod operation.

•

Type: Prod Link

•

Operation: Produce 1 year

16. Create the Acid Job load. What does this load model? What temperatures are used? Similar to 1 Year Production, this load case is used to model the current string with the temperature profiles,

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Chapter 7: Tube

pressure, and data imported from a Prod operation. For this load, we use the Acid Job operation.

•

Type: Prod Link

•

Operation: Acid Job


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Chapter 7: Tube

17. Calculate results. Click

to calculate results.

Blue highlighted loads must be calculated because there has been a data change since the load was last calculated.

18. Review the internal, external, and differential pressures for the following loads: Initial Conditions, Steady State Production (t), Full Evacuation, Pressure Test, and Tubing Leak. Use Results > Single Load > Pressures. Use the Data Selection dialog to select the curves, and Results Wizard List to change loads displayed in the plot.

Select the load from the Results Wizard List.

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Chapter 7: Tube


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Chapter 7: Tube

a) What is the internal pressures for the Full Evacuation load? The Full Evacuation load assumes the pipe contains air. b) Which loads are burst and which are collapse? Negative differential pressure means the load is collapse, and positive differential pressure means the load is a burst load. Tubing Leak and Full Evacuation are collapse loads. Steady State Production (t) and Pressure Test are burst loads. c) What is the external pressure profile for all those loads? The external pressure profile is based on entry in the Wellbore > Annulus Contents. Pressure is due to 10.0 ppg CaCl2, the packer fluid.

19. View Results > Multiple Loads > Burst Safety Factor, and Results > Multiple Loads > Differential Pressure for all defined tubing loads in two horizontal windows.

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Chapter 7: Tube

a) Based on the Differential Pressure plot, which load(s) is driving the burst design? The load(s) that results in the highest differential pressure (lowest safety factor) are the ones that control the design. In this example, the burst design is controlled by the Production Shut In, and Pressure Test loads.


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Chapter 7: Tube

b) Based on the Differential Pressure plot, which load(s) is driving the collapse design? Full Evacuation is driving the collapse load.

20. Replace the Differential Pressure plot with the Results > Multiple Loads > Collapse Safety Factor plot. Do the plots suggest your design is acceptable in of burst and collapse? Because the

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Chapter 7: Tube

load safety factors exceed the burst and collapse design factors, the plots suggest the design is safe in of burst and collapse.

21. View Results > Multiple Loads > Axial Safety Factor, and Results > Multiple Loads > Axial Loads for all defined tubing


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Chapter 7: Tube

loads in two horizontal windows. Based on these plots, is the axial design criteria met? No. The Acid Job, Tubing Leak, 1 Year Production, and Steady State Production (t) loads do not meet the axial design criteria.

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Chapter 7: Tube

22. Using the Results > Multiple Loads > Design Limit plot, which loads do not appear to meet the triaxial design criteria?

Loads that cross the triaxial limit curve do not meet the triaxial design criteria. In this example, the following loads cross the limit: Steady State Production (t) Production Shut In Pressure Test Acid Job 1 Year Production

23. Using the Results > Multiple Loads > Triaxial Safety Factor plot, which loads do not appear to meet the triaxial design criteria?

Loads that fall to the left of the Reference curve do not meet the triaxial design criteria. In this example, the following loads do not meet the criteria: Pressure Test Acid Job 1 Year Production Production Shut-in Steady State Production (t)


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Chapter 7: Tube

24. Refer to Results > Summaries > Minimum Safety Factor. a) Which loads fail triaxial design?

Refer to the table at the bottom of the table to determine that L9 and L3 refer to the Acid Job and 1 Year Production loads.

b) Why is the Pressure Test load not showing as failing the triaxial design criteria on this table? Although the Pressure Test load safety factor is less than the design safety factor, the Acid Job safety factor is less over the same depth interval. This table displays the minimum safety factor, and therefore presents the Acid Job.

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Chapter 7: Tube

25. Investigate tubing movement for the 1 Year Production operation. Use Results > Summaries > Movement. Select the load from the list. One row is created for each tubing interval with the top at the tubing hanger or a packer, and the base at a packer. There is no entry for the tail pipe below the deepest packer. Hooke’s Law column displays the length change attributed to the Hooke’s Law effect, reflecting the elasticity of the material. Buckling column displays length change due to buckling. Balloon column displays length change due to pressure differential. Thermal column displays length change due to temperature change. Total column displays the sum of all length changes. For Initial Condition, Total is nonzero only when there is displacement at the surface due to pick-up or slack-off applied after the packer is set. For all other loads, the total movement is zero if no seal movement is allowed. Seal movement is specified on the Packer Details dialog.

a) Why does the sum of all the movements equal zero? The tubing is fixed at the hanger at the top and by the packer at the bottom, so there is no movement. b) Is there a buckling issue? Yes, there is buckling.


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Chapter 7: Tube

26. What force is required to prevent buckling for the 1 Year Production load? Use Results > Summaries > Tubing Load. Negative axial force represents compression (Up), while positive values represent tension (down). High dogleg and torque values appear in intervals where the tubing is buckled.

The additional pick-up force required to prevent the tubing from buckling is calculated and displayed here when buckling is present. Apply this force using the Axial Load change After Packer Set field on the Packers > Details tabs. The friction force will be non-zero only if the Friction option has been enabled on the Loads > Design Parameters > Analysis Options tab.

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Chapter 7: Tube

27. To begin to solve buckling issues, allow 18 ft downward tubing movement with a “nogo”. Use Wellbore > Packers.

The downward movement represents the length of sealing assembly allowed to move in and out of the packer bore.

28. Calculate results. What is the total tubing movement now for the 1 Year Production load?

This is the actual movement.

29. For the 1 Year Production load, what force will be required to a tool, and how long can the tool be? Use Results > Summaries > Tool age. Based on the doglegs due to buckling combined with wellbore tortuosity, the Tool age Summary displays the


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Chapter 7: Tube

critical depth at which a tool may get stuck, the maximum tool length that can through the tubing, and the force required to make the tool for the selected load. If the tool does not freely, the maximum tool length which es freely will be displayed along with the force required to the rest of the tool. If the tool es freely, the Max Length which es Freely value will be displayed as ---.

30. Are any loads outside the packer operating envelope? Use Results > Multiple Loads > Packer Operating Envelope.

All loads are within the packer operating envelope.

31. Review Results > Single Load > Packer Schematic. The packer Schematic displays a schematic for each of the packers defined in

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Chapter 7: Tube

the string along with important packer forces computed as part of the analysis.

Use the Data Selection dialog to select the information you want displayed, including the packer, load, and force.


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Chapter 7: Tube

32. Review the packer loads for all loads. Use Results > Multiple Loads > Packer Loads. Refer to the online help for a description of the information displayed.

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Chapter 8

MultiString The WELLCAT™ software MultiString module is used to perform annular fluid expansion (AFE) and wellhead movement (WHM) analysis, which take into all the casings and tubings inside the wellbore. The annular fluid expansion and wellhead movement analysis can be performed while drilling or at any point in time during the life of the well. It is also used to evaluate the integrity of the casings and tubings under the annular fluid expansion and wellhead movement displacement conditions. Since the entire well is considered as a whole, as compared to the Casing and Tubing modules which take into only a single string at a time, results and input data from all the other modules are used in performing MultiString analysis. The MultiString module is an advanced Windows-environment engineering tool used for: •

Predicting annular fluid expansion in each annulus during production operations

•

Performing stress analysis for pipes, using custom loads, and taking into the annular fluid expansion

•

Predicting wellhead movement of the entire system while drilling and landing casings and during production operations

•

Performing a hanger lift-off analysis by specifying lock ring ratings for each casing

•

Including the effect of soil interaction in the wellhead movement calculations

•

Modeling compensator loads in the wellhead movement analysis

•

Performing sensitivity analysis on the wellhead movement results by specifying a -defined point of fixity


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Chapter 8: MultiString

Workflow Overview In this section of the course, you will learn how to use the MultiString module. You will perform annular fluid expansion and wellhead movement analysis during the Produce 1 year operation. For the annular fluid expansion analysis, assume that all except the 13 3/8” casing annuli are vented. Since the 13 3/8” casing TOC is well below the 20” casing shoe, any annular pressure build-up above the fracture gradient at the 20” casing shoe is assumed to be leaked off into the formation. Stresses acting on the 13 3/8” and 20” casings due to this annular pressure build-up will be analyzed. For the wellhead movement analysis, define the loading history of the well in order as each casing is landed in place. The movement of the wellhead will be computed and the load distribution between all the casings will be analyzed.

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Workflow Steps Annular Fluid Expansion 1. Use File > Import > Transfer File to import 5000_1_13_WELLCAT_Start_MultiString.edm.xml. Activate the MultiString module. 2. Define the annular fluid expansion analysis details. Use the following parameters: •

For all strings, use Undisturbed as the Drill Operation

•

All strings annuli are vented except for the 13 3/8” Intermediate Casing

•

Use the Produce 1 Year Prod operation as the Final Operation to define the final temperature condition for all strings

•

There is no gas cap present for any string

•

There is no fluid bled from the annulus of any string

•

For the 13 3/8” Intermediate Casing, allow annular pressure to enter the formation. Use the prior shoe depth as the Depth at Leak-Off and a 12.5 ppg Leak-off-Density.

3. Using Analysis > Annular Fluid Expansion > Define Custom Loads, define the custom loads as follows: •

20” Surface Casing: AFE and Max Burst using default data

•

13 3/8” Intermediate Casing: AFE and Max Collapse using default data

•

Do not calculate any loads for other strings

4. Where do each of the custom loads (AFE, Max Burst, and Max Collapse) apply pressures? 5. Where do the default fluid profiles for the custom loads come from?


8-3


6. Why do we not want to analyze the Max Collapse load for the 20” Surface Casing? 7. Calculate results for annular fluid expansion only. 8. Review Results > Summaries > Multi-String AFE. a) Where do you see annular pressure buildup? b) What is the Incremental AFE Volume? 9. Analyze the axial loads for the 20” casing due to the annular pressure build-up in the 13 3/8” casing annulus. Using Results > Summaries > Axial Load, compare the internal pressure for the Initial Conditions and 20”Surface Casing-AFE loads. What causes the difference in the internal pressure? 10. Are the design factors for the 20” Surface Casing - AFE load acceptable? 11. Analyze the axial loads for the 13 3/8” casing due to the annular pressure build-up in the annulus of the 13 3/8” casing. Using Results > Summaries > Axial Load, compare the external pressure for the Initial Conditions and 13 3/8”Intermediate CasingAFE loads. What causes the difference in the external pressure? 12. Are the design factors for the 13 3/8” Intermediate Casing - AFE load acceptable?

Wellhead Movement Analysis 13. Wellhead movement analysis requires the specification of the outermost string to which the wellhead will be attached. In this example, the 20” surface casing will be considered as the outermost string. Consequently, all drilling events prior to the setting and cementing of the 20” surface casing, although they may have been modeled in the Drill module, do not have any impact on the wellhead movement analysis. Define the static loads for each string

8-4



using the following data. The axial load exerted on the 20” casing when installing the wellhead was 5,000 lbf. String

Hang-Off Drillstring in BOP

Nipple-Up BOP

NippleDown BOP

Nipple-Up Tree

20” Casing

Undefined

50 kips

Undefined

Undefined

13 3/8” Casing

Undefined

Undefined

Undefined

Undefined

9 5/8” Casing

Undefined

Undefined

Undefined

Undefined

7” Production Tieback

Undefined

Undefined

Undefined

Undefined

3 1/2” Tubing

Disabled

Disabled

50 kips

5 kips

a) What is the Installation and Static Load Definition dialog used for? b) What is Point of Fixity used for? c) What string does the WELLCAT software assume the wellhead is attached to? d) What is the difference between the String-Dependent Static Loads and the String-Dependent Installation Components? 14. Specify the following loads, in the order specified below, that will be applied to the wellhead, and the sequence in which they will be applied. Why is the Produce 1 Year operation only shown for the 3 1/2” Production Tubing? Use Analysis > Wellhead Movement > Load History Definition. String

Load Name

20” Surface Casing

Install Wellhead


Nipple-Up BOP

13 3/8” Intermediate Casing





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8-6

String

Load Name




Run 9 5/8” Casing




Drill 8 1/2” Hole






Run 7” Casing


Cement 7” Casing




Run and Set 7” Tieback

3 1/2” Production Tubing

Nipple-down BOP


Nipple-Up Tree


Produce 1 Year



The Load Condition list contains the names of all strings and the static and thermal load cases that are defined for them. This tree structure allows you to view all previously defined drilling operations and static loads for the strings included in the wellhead movement analysis.

To build the Load History, you must first select a load from the Load Condition list, and then click the arrow to transfer the selected load to the Load History event table. For this example, start with the Install Wellhead load for the 20” surface casing. Another way to transfer loads is to click the string name in the Load Condition list, use the arrow to transfer all the loads to the Load History events, and then adjust the load sequence in the Load History list by clicking Up or Dn

15. Calculate wellhead movement results. Do not include soil interaction, or liftoff analysis. Click to calculate results.


8-7


16. Analyze wellhead movement for each applied load using Results > Summaries > MultiString Wellhead Movement > Displacement.

•

What does the data in the Incremental column tell you?

•

What do negative numbers in the summary represent?

•

What does the data in the Cumulative column tell you?

•

How much does the wellhead move during one year of production?

17. Review the axial load distribution, without bending, for each string in the well for the defined loads using Results > Summaries > MultiString Wellhead Movement > Forces.

•

8-8

What does a negative axial load indicate?



•

If the axial load is NA, what does that mean?

•

What is the axial load acting at the tubing hanger while producing for 1 year?

18. Using Results > Single Load > Axial Load > Wellhead Movement, review the axial loads in all strings landed in the well during the Produce 1 Year operation. Are previous operations considered when calculating these results? 19. What is the load between the 13 3/8” and the 20” casing during the Produce 1 Year operation? Use Results > Single Load > Axial Loads > Wellhead Loads.


8-9


Workflow Solution Annular Fluid Expansion 1. Use File > Import > Transfer File to import 5000_1_13_WELLCAT_Start_MultiString.edm.xml. Activate the MultiString module by clicking the MultiString icon ( ) on the Product toolbar. You can also select Tools > Select Product > MultiString. 2. Define the annular fluid expansion analysis details. Use the following parameters: •

For all strings, use Undisturbed as the Drill Operation

•

All strings annuli are vented except for the 13 3/8” Intermediate Casing

•

Use the Produce 1 Year Prod operation as the Final Operation to define the final temperature condition for all strings

•

There is no gas cap present for any string

•

There is no fluid bled from the annulus of any string

•

For the 13 3/8” Intermediate Casing, allow annular pressure to enter the formation. Use the prior shoe depth as the Depth at Leak-Off and a 12.5 ppg Leak-off-Density.

Use Analysis > Annular Fluid Expansion > Define Details.

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Select a string in the String List. Information displayed in the other fields is associated with the currently selected string.

A Drill operation can be used to describe the initial conditions for the selected string. The default value is Undisturbed. Use this default for all of the strings.


8-11


Specify the pressure in equivalent mud weight at which the formation will fracture, thus allowing the trapped annular fluids to leak into the formation. Also, enter the measured depth associated with this value (usually the previous shoe depth). Leave as 0 for all the other strings.

In this workflow, we assume there is no gas cap present. If you specify there is gas present, indicate the type of gas, and the location.

8-12



The Volume Bled field allows you to specify that part of the fluid will be evacuated from the annulus, maybe through a bleed-off mechanism. This option can also be used when crushable foam is employed (not used in this example).

By checking the Vented Annulus check box, you assume that the annulus is open to the atmosphere and no pressure build-up will occur due to fluid expansion. In this case, all annuli except the 13 3/8” will be vented.


8-13


Finally, select a Prod operation to define the final temperature condition. This selection applies to all strings. Select Produce 1 year.

3. Using Analysis > Annular Fluid Expansion > Define Custom Loads, define the custom loads as follows:

8-14

•

20” Surface Casing: AFE and Max Burst using default data

•

13 3/8” Intermediate Casing: AFE and Max Collapse using default data

•

Do not calculate any loads for other strings




8-15


8-16



4. Where do each of the custom loads (AFE, Max Burst, and Max Collapse) apply pressures? The AFE custom load cases consist of the annular fluid expansion calculated pressures applied inside and outside of the selected string. Max Burst will apply annular fluid expansion pressure only in the inside of the selected string. Max Collapse will apply the annular fluid expansion pressure only outside the selected string. 5. Where do the default fluid profiles for the custom loads come from? Refer to the online help.


8-17


6. Why do we not want to analyze the Max Collapse load for the 20” Surface Casing? Because it is vented there will not be any pressure build up in the annulus. 7. Calculate results for annular fluid expansion only. Click calculate results. Check only Calculate AFE.

Click Calculate to calculate results for loads selected on the AFE Custom Load Description dialog.

8-18


to


8. Review Results > Summaries > Multi-String AFE. Only the 13 3/8” casing annuli with TOC below prior shoe was not vented. The annular pressure build for this annulus was limited to the 12.5 ppg fracture gradient at the 20” shoe. The maximum surface pressure for the 13 3/8” casing annuli is 274 psi. All other annuli were vented and, thus, have no annular pressure build-up.

The Incremental AFE Volume result represents the change in annular fluid volume as the fluid expands because of the increase in temperature. As shown, this volume change is reported even when the annulus was assumed to be vented.

a) Where do you see annular pressure buildup? b) What is the Incremental AFE Volume? 9. Analyze the axial loads for the 20” casing due to the annular pressure build-up in the 13 3/8” casing annulus. Using Results > Summaries > Axial Load, compare the internal pressure for the


8-19


Initial Conditions and 20”Surface Casing-AFE loads. What causes the difference in the internal pressure?

The 274 psi annular fluid expansion pressure is added to the internal pressure profile.

8-20



10. Are the design factors for the 20” Surface Casing - AFE load acceptable? Use Results > Summaries > Safety Factor.

Triaxial and axial safety factors do not meet design factor criteria.

11. Analyze the axial loads for the 13 3/8” casing due to the annular pressure build-up in the annulus of the 13 3/8” casing. Using Results > Summaries > Axial Load, compare the external


8-21


pressure for the Initial Conditions and 13 3/8”Intermediate CasingAFE loads. What causes the difference in the external pressure?

The 274 psi annular fluid expansion pressure is added to the external pressure profile.

8-22



12. Are the design factors for the 13 3/8” Intermediate Casing - AFE load acceptable? Use Results > Summaries > Safety Factor.

Safety factors meet design factor criteria.

Wellhead Movement Analysis 13. Wellhead movement analysis requires the specification of the outermost string to which the wellhead will be attached. In this example, the 20” surface casing will be considered as the outermost string. Consequently, all drilling events prior to the setting and cementing of the 20” surface casing, although they may have been modeled in the Drill module, do not have any impact on the wellhead movement analysis. Define the static loads for each string using the following data. The axial load exerted on the 20” casing


8-23


when installing the wellhead was 5,000 lbf. Use Analysis > Wellhead Movement > Installation and Static Load Definition.

8-24

String

Hang-Off Drillstring in BOP

Nipple-Up BOP

NippleDown BOP

Nipple-Up Tree

20” Casing

Undefined

50 kips

Undefined

Undefined

13 3/8” Casing

Undefined

Undefined

Undefined

Undefined

9 5/8” Casing

Undefined

Undefined

Undefined

Undefined

7” Production Tieback

Undefined

Undefined

Undefined

Undefined

3 1/2” Tubing

Disabled

Disabled

50 kips

5 kips




8-25


8-26




8-27


8-28



a) What is the Installation and Static Load Definition dialog used for? It allows you to define static loads for each string for use during wellhead movement analysis. After the load is defined, you can use the Analysis > Wellhead Movement > Load History Definition dialog to specify static and thermal loads applied to the wellhead, and the sequence they are applied. b) What is Point of Fixity used for? The point of fixity is the depth below which the outermost string has zero displacement. By default, this is the TOC or mudline (for drive pipes). You can use this option to perform a sensitivity analysis on the wellhead movement loads and displacements on the system by specifying a new depth of point of fixity. c) What string does the WELLCAT software assume the wellhead is attached to? The outermost string is the string to which the wellhead will be attached; in other words, MultiString assumes


8-29


the wellhead is installed on the outermost string. In this example, the outermost string is the 20” surface casing. d) What is the difference between the String-Dependent Static Loads and the String-Dependent Installation Components? The String-Dependent Static Loads section must be defined on a string-by-string basis. The Hang-Off Drillstring in BOP static load models including the hanging weight of the drill string in the wellhead. The Nipple Up/Down BOP static loads model nippling up/down a BOP stack on the wellhead. Similarly, the Nipple-Up Tree static load models nippling up a tree on the wellhead. All of these forces will be considered as acting downwards, with the exception of Nipple-Down BOP, which acts upward. The String-Dependent Installation Components section is used to define details about the lock ring ratings and compensator loads for each string. The Lock-Ring Rating limit is specified as a limit for negative force between a string and the next outer string to keep the slip assembly together. This limit is used in lift-off analysis. 14. Specify the following loads, in the order specified below, that will be applied to the wellhead, and the sequence in which they will be applied. Why is the Produce 1 Year operation only shown for the 3 1/2” Production Tubing? Use Analysis > Wellhead Movement > Load History Definition. The Produce 1 Year operation is shown in the load condition table only for the innermost string in the well. However, the effect of this thermal load is seen by all the strings in the well at the time the event occurs. This is also true for all the Drill operations. The wellhead movement effect for any static load or thermal operation is seen by all the strings that are present in the well when that operation occurs. MultiString allows you to include only one Prod operation per wellhead movement analysis.

8-30

String

Load Name


Install Wellhead


Nipple-Up BOP








Run 9 5/8” Casing





String

Load Name


Drill 8 1/2” Hole






Run 7” Casing


Cement 7” Casing




Run and Set 7” Tieback


Nipple-down BOP


Nipple-Up Tree


Produce 1 Year


8-31


The Load Condition list contains the names of all strings and the static and thermal load cases that are defined for them. This tree structure allows you to view all previously defined drilling operations and static loads for the strings included in the wellhead movement analysis.

To build the Load History, you must first select a load from the Load Condition list, and then click the arrow to transfer the selected load to the Load History event table. For this example, start with the Install Wellhead load for the 20” surface casing. Another way to transfer loads is to click the string name in the Load Condition list, use the arrow to transfer all the loads to the Load History events, and then adjust the load sequence in the Load History list by clicking Up or Dn

15. Calculate wellhead movement results. Do not include soil interaction, or liftoff analysis. Click to calculate results.

8-32



16. Analyze wellhead movement for each applied load using Results > Summaries > MultiString Wellhead Movement > Displacement.

•

What does the data in the Incremental column tell you? The incremental displacement represents the movement of the wellhead due to a specific load. This movement represents the applied force from that load divided by the current system stiffness.

•

What do negative numbers in the summary represent? Negative incremental represents downward movements, while positive incremental represents upward movement.

•

What does the data in the Cumulative column tell you? The cumulative displacement represents the position of the wellhead relative to where it was when it was landed.

•

How much does the wellhead move during one year of production? The wellhead move up over 1 ft during.


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17. Review the axial load distribution, without bending, for each string in the well for the defined loads using Results > Summaries > MultiString Wellhead Movement > Forces.

•

What does a negative axial load indicate? Negative loads are compression, and positive are compression.

•

If the axial load is NA, what does that mean? For all the strings that are not landed in the wellhead when a particular load event occurs, NA is displayed as the axial force at the hanger depth.

•

What is the axial load acting at the tubing hanger while producing for 1 year?

The load in the tubing hanger for the year production operation is listed here. For every string in the wellbore, the Axial Load columns display the axial force acting at the hanger depth for that string.

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18. Using Results > Single Load > Axial Load > Wellhead Movement, review the axial loads in all strings landed in the well during the Produce 1 Year operation. Are previous operations considered when calculating these results? This spreadsheet or plot displays the cumulative axial force for the strings currently in the well as a result of the wellhead movement due to each load occurring during the life of the well. The updated axial force during a load is calculated for each string based on the string’s stiffness. (String stiffness is dependent on the cross-sectional area, Young’s Modulus, and string length.) The measured depths associated with the axial forces are automatically determined and are based on the well configuration (mud line, cement tops, etc.). Use to select the operation. Toggle between plot and spreadsheet view.

19. What is the load between the 13 3/8” and the 20” casing during the Produce 1 Year operation? Use Results > Single Load > Axial Loads > Wellhead Loads. This spreadsheet displays the loads between strings that are associated with one or more wellheads. This information is especially critical when lock ring ratings have been specified. This result can be used to determine if the loads are going to exceed the lock ring ratings between strings, thereby causing a hanger lift-off situation. If the Liftoff Analysis option has been checked in the Calculate check box and a lock ring rating for a particular slip is exceeded,


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the WELLCAT software shows the new forces after redistribution of loads between strings due to unseating of the slip. The title displays the depth of the wellhead.

force between 13 3/8” and 20” casings

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