WellPlan Exercie Book

WELLPLAN Exercise Book 2003.5.0.2 (EDM 2003.5.0.2 (03.13.03)) copyright © 2003 by Landmark Graphics Corporation

Part No. 161753, Rev. A, V2003.5.0.2

September 2003

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Landmark

WELLPLAN Exercise Book

Contents Contacting Support ............................................................................................................. WELLPLAN Exercise Overview ....................................................................................... Exercise 1: Creating the Data Hierarchy ............................................................................ Exercise 2: Specifying Tubular Properties, and Working With Catalogs .......................... Exercise 3: Using the Case Menu ....................................................................................... Exercise 4: Using Torque Drag Analysis ........................................................................... Steps and Questions ..................................................................................................... Answers ....................................................................................................................... Exercise 5: Using Hydraulics Analysis .............................................................................. Steps and Questions ..................................................................................................... Answers ....................................................................................................................... Exercise 6: Using Well Control Analysis ........................................................................... Steps and Questions ..................................................................................................... Answers ....................................................................................................................... Exercise 7: Using Surge Analysis....................................................................................... Note .............................................................................................................................. Steps and Questions ..................................................................................................... Answers ....................................................................................................................... Exercise 8: Using Cementing - OptiCem ........................................................................... Steps and Questions ..................................................................................................... Answers ....................................................................................................................... Exercise 9: Using Critical Speed Analysis ......................................................................... Steps and Questions ..................................................................................................... Answers ....................................................................................................................... Exercise 10: Using Bottom Hole Assembly Analysis ........................................................ Steps and Questions ..................................................................................................... Answers ....................................................................................................................... Exercise 11: Using Stuck Pipe Analysis............................................................................. Steps and Questions ..................................................................................................... Answers ....................................................................................................................... Exercise 12: Using Notebook ............................................................................................. Steps and Questions .....................................................................................................

September 2003

Contents

3 11 14 16 18 23 23 25 33 33 36 50 50 54 67 67 67 69 84 84 86 99 99 100 107 107 107 110 110 111 114 114

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September 2003

WELLPLAN Exercises

WELLPLAN Exercise Overview

1

The exercises in this book are designed to familiarize you with WELLPLAN. All of the exercises analyze a single well, however not all exercises analyze the same hole section. You will analyze running and cementing an 11 3/4” liner. You will also analyze drilling the 14 3/4” hole section which is drilled after setting the liner. This well has a weak zone that complicates much of the design. Exercise 1: Creating the Data Hierarchy In this exercise you will create a new company, project, site, well, wellbore, design, and case. Exercise 2: Specifying Tubular Properties and Working With Catalogs In this exercise, you will create a new pipe grade and then use this pipe grade to create a new pipe in an inventory you create. You will also review creating a unit system and importing a catalog. Exercise 3: Using the Case Menu This exercise builds on the previous two exercises. Using the data hierarchy created in Exercise 1, you will specify additional data that defines the case you are analyzing. You will use the information you entered into the catalog in Exercise 2 as well as use the catalog you imported. At the end of this exercise, you will import an xml transfer file that contains data you will be analyzing during the rest of the course. The data you import is very similar to what you specified in the previous exercises. In order to ensure that all course participants have the same data for the rest of the exercises, an xml file is imported. Exercise 4: Using Torque Drag Analysis During this exercise, you will become familiar with using the Torque Drag module. You will analyze drilling the 14.75” hole section. You will use Drag Charts to quickly look for trouble areas. You will follow this analysis with the Normal Analysis for a more in depth investigation of certain areas. Landmark

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Exercise 5: Using Hydraulics Analysis During this exercise, you will use the Hydraulics module to determine the minimum flowrate to clean the 14.75” hole section. You will also determine the maximum flowrate to avoid turbulent flow, and optimize bit hydraulics. You will also determine the tripping schedule, and predict ECD while tripping. Exercise 6: Using Well Control Analysis In this exercise, you continue to analyze the 14.75” hole section. You predict the type of kick to expect given certain circumstances. You estimate the volume of the influx and the pressure to expect given the size of the influx. The kick tolerance is investigated and a kill sheet is prepared. Exercise 7: Using Surge Analysis This exercise examines the surge and swab pressures to expect while running the 11 3/4” liner. The exercise also examines tripping and reciprocating the 12 1/4” BHA in the 14 3/4” hole section. Exercise 8: Using Cementing - OptiCem This exercise analyzes cementing the 11 3/4” liner. Circulating and wellhead pressure are investigated, in particularly near the fracture zone. Exercise 9: Using Critical Speed Analysis This exercise examines a range of rotating speeds while drilling the 14 3/4” hole section to determine which speeds may result in damaging vibrations. Exercise 10: Using Bottom Hole Assembly Analysis This exercise predicts the behavior of the 12 1/4” BHA while drilling the 14 3/4” hole section. Exercise 11: Using Stuck Pipe Analysis Using the Stuck Pipe Analysis module, you will determine the loads required to set, trip, and reset the jar. You will determine the load required to backoff at a specified measured depth, as well as the load that will fail the string.

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Exercise 12: Using Notebook You will review the analysis options available within the Notebook module.

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Exercise 1: Creating the Data Hierarchy 1. Launch WELLPLAN (Start > Programs > Landmark EDM > WELLPLAN). 2. Enter EDM as the User ID and landmark as the Password on the login screen. 3. Create a new company. Using the Well Explorer, right-click on “EDM 2003.5db” and select New Company from the menu. 4. Specify Company properties. a) Using the Company Properties > General tab, rename the company Class. 5. Create a new project when prompted or by using File > New > Project. a) Use the Project Properties > General tab to specify project properties. Name the project Kananga. Use Mean Seal Level as the System Datum. 6. Create a new site when prompted by clicking the Yes button. a) Use the Site Properties > General tab to specify general site information. Name the site Largo North Platform. The Default Site Elevation is 114.8 feet above MSL. Use Grid as the North Reference. Do not apply a tight group. (Use Unrestricted.) 7. Create a new well when prompted by clicking the Yes button. a) Use the Well Properties > General tab to specify general well information. Name the well LPN-004. Use API units and no Tight Group. Leave other tab fields blank. b) Use the Well Properties > Depth Reference tab to specify the well depth reference, configuration (offshore or onshore), and to view a depiction of the datum. Create a datum titled DFE with a 114.8 ft elevation. This datum is the default datum. (Check the Default box.) The rig name is Scorpion 100. This is an offshore well in 328.1 ft of water. Specify an 84.8 ft wellhead elevation. 8. Create a new wellbore when prompted. 14

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a) Use the Wellbore Properties > General tab to define general information about the wellbore. Name the wellbore ST1. 9. Create a design for wellbore ST1. Name the design P1. Use DFE @ 114.8 ft (Scorpion 100) as the depth reference. This well is a sidetrack from wellbore 1. WELLPLAN isn’t concerned with tie-on information. Case > Wellpath Editor defines the wellpath that will be used for analysis. Other Landmark Drilling Software use sidetrack data. Because the data used in WELLPLAN training is also used for training of other software products that are concerned with tie-on information, this well is labeled ST1. 10. Create a case for design P1. Name the case 14 3/4” Hole Section.

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Exercise 2: Specifying Tubular Properties, and Working With Catalogs 1. Create a pipe grade named VMHCQ-125. This grade has the following properties: • Section Type: Casing/Tubing • Material: CS API 5CT • Minimum Yield Strength: 125 kpsi • Fatigue Endurance Limit: 25,000 psi • UTS: 135 kpsi 2. Create a new Casing/Tubing Catalog with a name of your choice. 3. In the new casing/tubing catalog, create another pipe with the following properties: • Nominal Diameter: 11 3/4” • Nominal Weight: 65 lbs • Grade: VMHCQ-125 • Body OD: 11.75” • Body ID: 10.682 in • Weight: 65 lbs. • Pipe Type: Special • Drift ID: 10.625 in • Internal Yield: 9,940 psi • Collapse Resistance: 6,540 psi • Body Yield Strength: 2,352,010 lbf

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• Linear Capacity: 0.1108 bbl/ft • Closed End Displacement: 0.1341 bbl/ft • Average Joint Length: 40.0 ft • Wall Thickness: 87.5 % • Plain End Cost: leave blank 4. Make a new Units set and name it ‘Class’. (Tools > Unit System) Base the new unit set on API units. In the Class unit set, make the following changes. Notice that the active Unit Set name is displayed in the bottom right corner of the Main Window. The active Unit Set is saved with the Case. a) Use the unit ‘psi/ft’ for Mud Weight. b) Has the unit for density changed? (Case > Fluid Editor) c) Activate the API unit set. (Tools > Unit System.) 5. Import a catalog of diverter subs using the file DS Catalog.xml. To import the catalog, highlight Catalogs in the Well Explorer and then right-click. Select Import from the right-click menu. Review the information in the catalog. Diverter subs will be used in the Surge exercise.

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Exercise 3: Using the Case Menu 1. Define the hole section, including the last casing, liner, and the open hole section. (Case > Hole Section Editor) The well depth is 17,968 ft. Use 12,534 ft of 13 5/8”, 88.2 lb/ft, Q-125 casing with 17.5” effective hole diameter. Enter the 11 3/4”, 65 ppf, VMHCQ125 liner. (You entered this in the last exercise.) Use Casing as the section type for liners. The effective hole diameter is 14.75. There is 1,837 ft of 12 1/4” open hole. Use .2 friction factor in cased hole and .3 in open hole. The open hole is gauge. 2. Define a simple drill string to become familiar with using the Case > String Editor. • String Depth: 17,968 ft • Drill Pipe: 12,589.24 ft, DP 5 in, 19.50 ppf, G, NC50(XH), P • Heavy Weight: 60 ft, HW Grant Prideco, 5 in, 49.7 ppf • Jar: 28 ft, JHM Bowen Hyd/Mech. 6 3/4” OD, 2.5” ID (Note: Adjust the jar length to 28 ft.) • Heavy Weight: 300 ft, HW Grant Prideco, 5 in, 49.7 ppf • Drill Collar: DC, 390 ft, 8” X 2.5”, 7 H-90 • Stabilizer: 5 ft, IBS, 10 5/8” FG, 8 X 2.5” • Drill Collar: DC, 390 ft, 8” X 2.5”, 7 H-90 • Stabilizer: 5 ft, IBS, 10 5/8” FG, 8 X 2.5” • Drill Collar (Non-mag): 31 ft, NDC 8” X 2.5”, 7 H-90 • Stabilizer: 5 ft, IBS, 10 5/8” FG, 8 X 2.5” • MWD: 30 ft, MWD 8, 8 x 2.5 in • Mud Motor: 30 ft, BHM 8, 8 x 2.5 in • Sub: 3 ft, BS 6, 6 x 2 1/2 in • Bit: Bi-Centered, 1 ft, 12.25” OD, 150 lbs, TFA = .614 18

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3. Import the wellpath data. Use File > Import > Wellpath Data to import the file WP2003_5TrainingWellpath.TXT. Your instructor will tell you where the file is. The column order and units are: MD (ft), Inc (deg), and AZ (deg). (Note: It is important that you correctly specify column order and units.) Review the wellpath data using Case > Deviation > Wellpath Editor. 4. Enter mud properties on the Fluid Editor. Click the New button to enter data for a new fluid. (Case > Fluid Editor). After you are finished inputting fluid properties, click the Activate button to indicate you want this fluid used in the analysis. Use the following properties: • Name: 15.1 ppg OBM • Density: 15.1 ppg • Type: Non Spacer • Base Type: Oil • PV: 24 cp at 120 degrees F • YP: 7 lbf/100ft2 at 120 degrees F • Rheological Model: Power Law a) What are the calculated Fann dial readings? 5. Copy all pore pressure and fracture pressure from the file WPPoreFrac.xls. (Copy over all data (if any) already present in the pore pressure and fracture pressure spreadsheets.) Use CTRL-C and CTRL-V to copy and paste the data. In Excel, highlight all columns and then copy. In WELLPLAN, highlight the first row and use CTRL-V to paste the data. 6. Specify the geothermal gradient. The surface ambient temperature is 80 degree F, the mudline temperature is 40 degrees F, and the temperature at TD is 279.5 degrees F. What is the geothermal gradient? 7. Specify mud pump and other circulating system data. The surface equipment rated working pressure is 6,000 psi, and the surface

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pressure loss is 100 psi. Define three pumps. Activate the 12-P-160 pump. Name

Vol/stk (gal/stk)

Max speed (spm)

Max Discharge Pressure (psi)

Horse Power (hp)

9-P-100

3.685

150

2790

900

10-P-130

3.984

140

3595

1170

12-P-160

6.433

120

3200

1440

8. Create the following tabs (View > Tabs) by renaming or creating additional tabs. Use window splitters near the scrollbars to create window panes. a) Create a tab titled Schematic. On that tab, create two vertical panes containing a Well Schematic-Full String and BHA-Not to Scale schematics. (One schematic in each pane.) Turn the header off in the Full String schematic. b) Create a tab titled Editors. Create two horizontal panes on that tab. Open the Hole Section Editor in one pane and String Editor in the other pane. c) Create a tab titled Deviation. Create two vertical panes. Open the Wellpath Editor in this tab. d) Create a tab titled Plots. Open the Inclination plot in this tab. 9. This exercise step demonstrates the Freeze Line. (Later in this course, this feature will be applied to more meaningful sensitivity analysis.) a) Using the Plot tab created in the previous step, place the cursor (arrow) on the data curve of the Inclination plot. Click the right mouse button, and select Freeze Line. Specify the color of the freeze line to be green and change the name of the curve. b) Using the Deviation tab, change the inclination near 2527 ft to 50 deg. Notice the two curves visible at 2,527 ft on the Inclination plot. c) Using the right mouse button, click on the previously frozen line. Select Hide Line. What happened to the line?

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d) Add a background logo to the plot. Right-click anywhere on the plot. Select the Background tab. Click the Bitmap button. Add the Halliburton logo to the plot. Your instructor can tell you the location of the file. e) Close the plot. 10. Generate a survey Vertical Section plot. (View Wellpath Plots Vertical Section) Use the window splitters to give this plot the entire workspace on the Deviation tab. 11. Change the width of the data curve on this plot to 3. (Hint: Rightclick on the curve and use right-click menu.) 12. Activate the Graphics Toolbar by clicking anywhere on the plot. 13. Use the Data Reader (third button from left on Graphics Toolbar) to determine the vertical section at TD. What is it? 14. Click on the Data Spreadsheet button (fourth button from the left on the Graphics Toolbar) to view X/Y coordinate data for the plot. Click the Arrow button (left button on Graphics Toolbar) to return to the plot view. 15. Click on the Properties button (right button on Graphics Toolbar) to open the Properties tabs. The following questions highlight the functionality of these tabs. (Hints: To easily view the changes to the plot, move the Properties tabs dialog box so that the plot is visible. Don’t forget to click the Apply button to implement changes.) a) Using the Axis tab, Draw the X axis where Y = 0, and remove the tick marks from the Y axis. b) Using the General/Grid tab, remove the grid lines from the plot. c) Using the Labels tab, change the Y axis label to ‘True Vertical Depth’. d) Using the Font tab, change the axis labels to green and italic. e) Using the Markers tab, display data markers every 50 data points. f) Using the Legend tab, turn off the legend. 16. Save this case. Landmark

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17. Export this Case at the Company level using the filename of your choice. 18. Import the data file WELLPLANTraining2003_5.xml. This transfer file contains data you will be analyzing during this training course. For the rest of the course, you will be using the well LPN-004, wellbore ST1 in the site Kananga of the Full Feature Oil Co. company. This well is exactly like the one you just finished creating. To ensure that everyone has the same data, we are using the imported data rather than the data you entered.

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Exercise 4: Using Torque Drag Analysis Steps and Questions 1. Open the case titled TDA 14 3/4” Hole Section 2. Activate the Torque Drag Analysis module and select Drag Chart analysis mode. 3. Copy the assembly for the 12 1/4” Hole Section case in the well LPN-0042, wellbore ST1 plan P1 to the 14 3/4” Hole Section case. Change the string depth to 17,968 ft. 4. Review the hole section information and make a note of the open hole section measured depth interval. (Case > Hole Section) 5. Activate the 15.1 ppg OBM. (Case > Fluid Editor) 6. Open the template torquedrag.tpt. Review the different tabs. (File > Workspace > Open Template) 7. Apply tortuosity to the interval below 4,680 ft. This well is actually a sidetrack of another well. Tortuosity should only be applied to planned wellpath data. It should never be applied to actual survey data. In this example, there is actual survey data above 4,680 ft. Use the Random Inc Dependent Az method. Apply 0.30 between 4,680 ft and 7,000 ft. Below 7,000 ft, apply 0.50 degrees. Use a 100 ft Angle Change Period and interpolate every 30 ft. Review the tortured wellpath data to observe the revised inclinations. 8. Specify 50 kips traveling assembly weight. Include bending stress magnification (check the box), use 31 ft as the contact force normalization length, and analyze all mechanical limitations (again, check associated boxes). (Case > Torque Drag Setup) 9. Analyze the open hole interval (16,131 - 17968 ft) every 100 ft. Use 20 kip WOB and 2000 ft-lbf torque at bit for rotating on bottom operation. Also analysis rotating off bottom, and both tripping in and out. There is no rotation while tripping. (Parameter > Run Parameters) 10. Does the Drag Chart analysis predict any problems in this interval?

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a) What does the Tension Point chart tell you? (View > Plot > Tension Point Chart or access the Drag Tension Point Chart tab) b) What does the Torque Point Chart tell you? (View > Plot > Torque Point Chart or access the Drag Torque Chart tab) c) What is the minimum WOB to avoid helical buckling while rotating on bottom? (View > Plot > Minimum WOB Chart or access the Drag Min WOB tab) Does the Drag Chart tell you where the string is buckling? If not, how could you find out where it is buckling? 11. Access the Normal Analysis mode. When using the Normal Analysis mode, where is the bit assumed to be? 12. Determine if buckling or fatigue is likely to occur for any selected operation mode. (View > Table > Summary Loads or click the Summary Load tab) 13. Where does the buckling occur while rotating on bottom? (View > Table > Load Data > Rotating On Bottom or click the Load/Stress Data tab) 14. Where is fatigue or tensile yield likely to occur: a) While tripping out? (View > Table > Load Data > Tripping Out) b) While rotation on bottom? (View > Table > Load Data > Rotating On Bottom) c) While rotating off bottom? (View > Table > Load Data > Rotating Off Bottom) 15. How could we solve the fatigue and yield problems in the string? Try adding a 8050 ft section of S grade, 19.5 ppf drill pipe near the surface. Does that remove the yield or fatigue prediction? 16. If fatigue is still a problem, try using a different class or a different weight of S grade pipe near the surface. 17. If the buckling near the bit is still a problem, what could you do?

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Answers 1. Double-click on the case name in the Well Explorer to open it. 2. Click the Torque Drag toolbar button, or use the Modules menu. 3. Using the Associated Data Viewer, right-click on the assembly you want to copy and select Copy from the menu. In the Well Explorer, highlight the case you want to copy the assembly to, right-click, and select Paste from the menu. 4. Use Case > Hole Section. The open hole interval is between 16, 131 and 17, 968 ft MD 5. Using Case > Fluid Editor, click once on the desired fluid to highlight it, then click the Activate button. Notice the tear drop next to the fluid indicating it is the active fluid. 6. Use File > Workspace > Open Template. 7. Use Case > Deviation > Wellpath Options.

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8. Use Case > Torque Drag Setup

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9. Use Parameter > Run Parameters

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10. Does the Drag Chart analysis predict any problems in this interval? a) Use View > Plot > Tension Point Chart or access the Drag Tension Point Chart tab

During a tripping in operation when the bit is at 17,431 ft the string is very close to buckling. Notice that this chart does not tell us anything about buckling while rotating.

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b) Use View > Plot > Torque Point Chart or access the Drag Torque Chart tab.

This plot does not indicate that torque is going to be a problem over this interval. Notice that the makeup torque is always greater than any expected torque while rotating.

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c) Use View > Plot > Minimum WOB Chart or access the Drag Min WOB tab. Does the Drag Chart tell you where the string is buckling? If not, how could you find out where it is buckling?

Over the interval analyzed, we can determine from this plot that the minimum WOB to avoid buckling varies from slightly over 0 kips to slightly less than 10 kips WOB. We know we must be buckled, because we specified 20 kips WOB in the analysis parameters. To determine where it is buckling, you must use the Normal Analysis mode.

11. Access the Normal Analysis mode using the Mode drop-down list. The bit is assumed to be at the string depth indicated on the Case > String Editor spreadsheet.

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12. Use View > Table > Summary Loads or click the Summary Load tab.

Using this table, we can see there are a variety of problems including pipe yield, fatigue, failure, and buckling. Refer to the online help for a definition of codes.

13. Use View > Table > Load Data > Rotating On Bottom. Notice that buckling occurs near the bit. Scroll down the table and notice there is also fatigue and yield problems further up the string.

14. Where is fatigue or tensile yield likely to occur: a) While tripping out, there are problems from the surface to 3,740 ft MD. Use View > Table > Load Data > Tripping Out. b) While rotating on bottom, there are yield and fatigue issues from 3,000 - 4,400 ft and also around 650 ft MD. Use View > Table > Load Data > Rotating On Bottom. c) While rotating off bottom, there are problems off and on from surface to 7,500 ft MD. Use View > Table > Load Data > Rotating Off Bottom.

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15. Adding a 8,050 ft section of S grade, P, 19.5 ppf drill pipe near the surface resolved some, but not all of the problems. 16. Using 25.6 ppf, first class pipe solves the problem. 17. If the buckling near the bit is still a problem, you could reduce the WOB. You probably won’t get rid of all the buckling.

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Exercise 5: Using Hydraulics Analysis Steps and Questions 1. Open the Case HYD 14 3/4” Hole Section 2. Open the workspace template hyd_template.tpt. 3. Select the Hydraulics application, and Hole Cleaning Operational from the Modules menu, or click the Hydraulics button and select Hole Cleaning - Operational from the Mode drop-down list. 4. The pressure response data for the mud motor in the current work string is 350 psi loss at 530 gpm and 350 psi loss at 900 gpm. Add this to the mud motor description. 5. Set the string depth to 17,968 ft to put the bit “on-bottom”. (Case String Editor) 6. What are the bit nozzle sizes? (Case

String Editor)

7. Use the Circulating System dialog to answer the following questions, or to perform the following steps. (Case Circulating System) a) What is the maximum working pressure specified? (Case Circulating System Surface Equipment tab) b) Specify surface pressure loss of 100 psi. c) Mark the pump name 12-P-160 the active pump. (Case Circulating System Mud Pumps tab) 8. Specify the cuttings transport analysis parameters. (Parameter > Transport Analysis Data) • ROP: 25 ft/hr • Rotary Speed: 90 rpm • Pump Rate: 400 gpm

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• Cuttings Diameter: 0.125 in • Cuttings Density: 2.500 sg • Bed Porosity: 36.00 % • MD Calculation Interval: 100 ft 9. Determine the minimum flow rate required to clean the wellbore. (View > Plot > Operational) 10. What is the percentage of cuttings suspended compared to the total volume of cuttings? 11. Change the yield point to 15 lbf/100 ft 2. Did this impact the required minimum flow rate and the bed height? 12. Determine the maximum flow rate. Analyze every 25 gpm between 400 and 600 gpm. Use the Annular Velocity Analysis. (Modules Hydraulics Annular Velocity) (Parameter Rates) Answer the following questions pertaining to this analysis. a) Use the Annular Velocity (View Plot Annular Velocity) plot to determine which flow rates result in non-laminar flow, and where does this flow regime occur? b) What is the critical annular pump rate inside the casing? What is the critical annular velocity inside the liner? (View Plot Annular Pump Rate) 13. Select the Pressure: Pump Rate Range (Modules Hydraulics Pressure: Pump Rate Range) analysis mode. a) Analyze flow rates between 400 gpm to 600 gpm in 25 gpm increments. Default Pumping Constraints from the Pump Data. Include tool joint pressure losses. (Parameter Rates) b) Specify ECD calculations to be performed at the casing shoe (16,132 ft) and at TD (17,968 ft). (Parameter ECD Depths) c) How is the maximum pump pressure calculated when it is defaulted from the pump data and there is more than one active pump? (Hint: Use the online help.) d) Generate a Pressure Loss report.(View Report Pressure Loss) At 425 gpm, what is the pressure loss gradient (psi/ft)

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down the inside of the drill pipe? (Hint: You can not read this directly.) Is there turbulence in the annulus at this flow rate? Record the bit, string, and annular pressure losses. e) Generate a Pressure Loss plot. (View Plot Pressure Loss) Use the Data Reader to determine the bit, string and annular pressure losses at 425 gpm. Compare these values against those in the Pressure Loss report. Do they match? 14. Perform Optimization Planning analysis to optimize bit hydraulics. (Modules Hydraulics Optimization Planning) a) Select the Opti Plan tab. b) Specify the analysis parameters. Default pump data. Specify a minimum nozzle size of 10/32nds and specify that 8 nozzles be used. Allow 60% pressure loss at the bit. Specify 80 ft/min as the minimum annular velocity. Include tool joint pressure losses, and do not allow turbulent flow in the annulus. (Parameter Solution Constraints.) c) What is the pump rate and nozzle sizes to maximize bit hydraulics if we want an HSI between 2 and 6? d) Close the Solution Constraints dialog. 15. Will the pump rate determined in the previous step clean the hole? 16. Can we pump at this pump rate using the nozzle sizes identified? Use Pressure: Pump Rate Range analysis and refer to the View > Plot > Pressure Loss plot. 17. We need to increase the pump pressure. Leave the current Pressure Loss plot open. Activate the 10-P-130 pump in addition to the 12-P160 pump. Did this help? Why or why not? (Hint: Refer to online help.) 18. De-activate the 10-P-130 pump. Change the liner size on the 12-P160 pump. Use a 5.5” liner size with a maximum discharge pressure of 5000 psi and 3.702 gal vol/stk. Now can we pump at the required pump rate to optimize hydraulics? 19. Perform a Swab/Surge Tripping Schedule (Modules Hydraulics Swab/Surge Tripping Schedule) analysis.

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a) Analyze closed and open end for both surge and swab scenarios. Use 523 gpm for the flow rate for the open ended swab and surge analysis. Use a 90 ft stand length and .5 ppg delta P. Use local nozzles (8X10). (Parameter Operations Data) b) Generate a Swab/Surge (View Report Swab/Surge) report. For the closed end swab scenario, how fast can the first few stands be tripped without causing a change greater than 0.5 ppg? 20. Perform a Swab/Surge Pressure and ECD analysis using the same data as in the previous step. Generate a Swab Closed End plot (View Plot Swab Closed End). What is the ECD at the casing shoe for a 50 sec/stand trip speed?

Answers 1. Open the Case HYD 14 3/4” Hole Section by double-clicking on it in the Well Explorer. 2. Open the workspace template hyd_template.tpt. Use File > Workspace > Open Template. 3. Select the Hydraulics application, and Hole Cleaning Operational from the Modules menu, or click the Hydraulics button to select the Hydraulics application, and select Hole Cleaning - Operational from the Mode drop-down list.

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4. Use Case > String Editor. Highlight the row associated with the mud motor. Use String > Data to add the mud motor data.

5. Use Case

String Editor.

Set the string depth to 17,968 ft to put the bit “on-bottom”.

6. Use Case

String Editor.

7. Use the Circulating System dialog to answer the following questions, or to perform the following steps. (Case Circulating System)

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a) What is the maximum working pressure specified? Use Case Circulating System Surface Equipment tab. Maximum working pressure

b) Specify surface pressure loss of 100 psi. c) Use Case

Circulating System

Mud Pumps tab.

Check the Active box to make the pump the active pump.

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8. Specify the cuttings transport analysis parameters using Parameter > Transport Analysis Data.

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9. Determine the minimum flow rate required to clean the wellbore using View > Plot > Operational. Use the Data Reader to read the minimum flowrate. Notice there is a bed height of approximately 1.5” when the flowrate is 400 gpm.

The minimum flowrate to avoid a cuttings bed is 451.7 gpm.

10. The percentage of cuttings suspended is less that one percent compared to the total volume of cuttings, which is almost 6.5%.

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11. Use the Case > Fluid Editor to change the yield point to 15 lbf/100 ft 2. Yes, this reduced the required minimum flow rate and the predicted bed height.

Minimum flowrate required using adjusted yield point.

12. To determine the maximum flow rate, use the Annular Velocity Analysis. Use Parameter Rates to specify range of flowrates to analyze. a) Use the Annular Velocity (View Plot Annular Velocity) plot to determine which flow rates result in non-laminar flow. In

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this example, turbulent flow occurs somewhere between 525 and 550 gpm.

This plot displays the annular velocity in each section of the well for each flowrate specified on the Rates dialog.

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b) What is the critical annular pump rate inside the casing? What is the critical annular velocity inside the liner? Use View Plot Annular Pump Rate.

Critical pump rate in the 13 5/8” casing is 667 gpm.

Critical pump rate in the 11 3/4” liner is 532.7 gpm.

13. Select the Pressure: Pump Rate Range (Modules Pressure: Pump Rate Range) analysis mode.

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a) Analyze flow rates between 400 gpm to 600 gpm in 25 gpm increments. Default Pumping Constraints from the Pump Data. Include tool joint pressure losses. (Parameter Rates)

Click Default from Pump Data to use data from the pumps marked as active on the Case > Circulating System > Mud Pumps tab.

b) Specify ECD calculations to be performed at the casing shoe (16,132 ft) and at TD (17,968 ft). (Parameter ECD Depths) c) If you have more than one active pump specified on the Circulating System/Mud Pumps tab, the Maximum Pump Pressure will be set equal to the minimum value entered for Maximum Discharge Pressure for any of the active pumps. d) Generate a Pressure Loss report.(View Report Pressure Loss) At 425 gpm, read the pressure loss inside the drillpipe. Then divide this pressure loss by the total length of the drillpipe. Refer to Case > String Editor for the length of the drillpipe. There is no turbulence in the annulus. Refer to the Annulus section of the report. e) Generate a Pressure Loss plot. (View Plot Pressure Loss) Use the Data Reader to determine the bit, string and annular pressure losses at 425 gpm. Yes, they match. Notice the bit pressure loss is low. 14. Perform Optimization Planning analysis to optimize bit hydraulics. (Modules Hydraulics Optimization Planning) a) Because of the template you imported, the Opti Plan tab is already setup to include the Optimization Planning analysis dialog (Solution Constraints). 44

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b) Specify the analysis parameters. Default pump data. Specify a minimum nozzle size of 10/32nds and specify that 8 nozzles be used. Allow 60% pressure loss at the bit. Specify 80 ft/min as the minimum annular velocity. Include tool joint pressure losses, and do not allow turbulent flow in the annulus. (Parameter Solution Constraints.)

c) A pump rate of 532.2 and nozzle sizes of 8 X 10/32nds is required to maximize bit hydraulics if we want an HSI between 2 and 6. d) Close the Solution Constraints dialog. 15. Yes, this pump rate will clean the hole. We determined that 426 gpm is required for hole cleaning.

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16. Use Pressure: Pump Rate Range analysis and refer to the View > Plot > Pressure Loss plot. At 532 gpm, the system pressure loss is greater than the pressure the pump can produce. Therefore, we can’t p[ump at this rate using the pump we have active.

17. We need to increase the pump pressure. Leave the current Pressure Loss plot open. Activate the 10-P-130 pump in addition to the 12-P160 pump. This doesn’t help because we are limited by the lesser pressure of the two active pumps. 18. De-activate the 10-P-130 pump. Change the liner size on the 12-P160 pump. Use a 5.5” liner size with a maximum discharge pressure of 5000 psi and 3.702 gal vol/stk. Don’t forget to reselect the active

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pump information on the Parameter >Rates dialog by clicking the Default from Pump Data button.

Add another row to indicate the pump with the new liner size.

It is close. You probably want a to try another liner size.

19. Perform a Swab/Surge Tripping Schedule (Modules Hydraulics Swab/Surge Tripping Schedule) analysis. a) Analyze closed and open end for both surge and swab scenarios. Use 523 gpm for the flow rate for the open ended swab and surge

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analysis. Use a 90 ft stand length. Use local nozzles. (Parameter Operations Data)

b) Generate a Swab/Surge (View Report Swab/Surge) report. For the closed end swab scenario, the first 101 stands can be tripped at 20 sec per stand.

20. Perform a Swab/Surge Pressure and ECD analysis using the same data as in the previous step. Generate a Swab Closed End plot

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(View Plot Swab Closed End). The ECD at the casing shoe for a 50 sec/stand trip speed is 15.01 ppg.

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Exercise 6: Using Well Control Analysis Steps and Questions 1. Open the Case WCN 14 3/4” Hole Section. 2. Select the Well Control application, and Expected Influx Volume from the Modules menu, or click the Well Control button and select Expected Influx Volume from the Mode drop-down list. 3. Review the Geothermal Gradient. 4. Specify the use of the Steady-State Circulation Model for the well control analysis. (Parameter > Temperature Distribution) Specify a flow rate of 500 gpm and a flow line temperature of 104 degrees Fahrenheit. Click OK. 5. Generate a Temperature Distribution Plot. (View > Plot Temperature Distribution) Answer the following questions. a) Why does the geothermal gradient profile change slope? b) What do the annulus and string curves represent? 6. To determine the type of kick encountered, specify a Circulation Flowrate of 520 gpm and a Kick Interval Gradient of 0.80. (Parameter > Kick Class Determination) Click Apply and answer the following questions. a) What type of kick would occur in this situation? Why? b) What is the difference between the interval pressure where the kick occurred and the static BHP (psi)? 7. After the Kick Class has been determined, you can calculate the estimated influx volume. a) Specify that the kick detection equipment is based on flowrate, and can detect a 40 gpm flowrate change. (Parameter > Influx Volume Estimation > Kick Detection Method tab) b) Specify the reservoir properties. The porosity of the reservoir is 25%, the permeability is 10 md, the reservoir thickness is 100 ft

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and the rate of penetration is 25 ft/hr. (Parameter > Influx Volume Estimation > Reservoir tab) c) Crew reaction times have been entered for you. What is the total crew reaction time specified from detection of kick up to and including closing the choke? This is modeling a “soft shut-in”. How could a “hard shut-in” be modeled? (Parameter > Influx Volume Estimation > Reaction Times tab) d) In this scenario, what size influx was predicted? (Parameter > Influx Volume Estimation > Results tab) e) Change the detectable flowrate variation to 20 gpm. Click Apply to process the changes. Now what is the predicted influx size? 8. Now that we know the expected influx volume, we will analyze the pressures associated with a kick of this size. Select Kick Tolerance from the Mode drop-down list. First, we must finish entering data required to define the current kick situation. 9. Use the Circulating System dialog (Case > Circulating System) to answer to following questions, or perform the following steps. a) What is the maximum working pressure specified on the Surface Equipment tab? b) On the Mud Pumps tab, mark the pump name 12-P-160 with the 3.702 gal/stk volume the active pump. c) Click OK to activate your changes and close the dialog. 10. Configure well control options. (Case > Well Control Setup) Specify the BOP rating to be 10,000 psi, and the casing burst rating to be 6,540 psi. Use an 80% casing burst safety factor. We will be using the “Wait and Weight” method to kill the well. A leak off test was run with 15.1 lb mud. The leak off pressure was 1,900 psi. (Case > Well Control Setup Operational tab) Click Apply. 11. Use the Steady-State Circulation temperature model (Parameter Temperature Distribution) to estimate the influx volume. The flowline mud temperature is 104 degrees Fahrenheit, the flowrate is 500 gpm and the mud density is 15.1 ppg. a) What flowrate is represented on this dialog? (Hint: Use the Help.) Landmark

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b) Click OK to activate your changes and close the dialog. 12. The Kick Class was determined earlier in this exercise while estimating the influx volume. What Circulation Flowrate is entered (Parameter > Kick Class Determination) dialog? Is it the kill circulation rate? 13. Now we must specify information that will be used to simulate and analyze the results of circulating the influx. (Parameter > Kick Tolerance) Assume a gas influx. Specify a kill rate of 130 gpm, with a kill mud gradient of .55 psi/ft. We will be circulating a 14 bbl influx. We are interested in analyzing the situation at the casing shoe (16,131 ft). We are planning our next casing shoe at 17,968 ft. Click OK to accept your changes and close the dialog. a) What is the correct interval to analyze if we want to check the next casing shoe depth of 17,968 ft? 14. Answer the following questions pertaining to the results of the Kick Tolerance analysis. All analysis results (plots and schematics) are available via the View menu. a) Determine the maximum annular pressure to expect at the depth of interest. (View > Plot > Pressure at Depth) Use the data reader to determine the maximum pressure. What is the maximum pressure? What volume of kill mud had been pumped when this pressure occurred? Why doesn’t the curve have a constant slope? b) Click the right mouse button on the curve and select Freeze Line. (Click the arrow on the Graphics Toolbar to exit Data Reader mode.) Change the color of the curve to purple. Change the Legend description to “Max Pressure at Shoe”. Click OK. Do not close the plot. c) Change the depth of interest to 17,000 ft. (Parameter > Kick Tolerance) Determine the maximum pressure to expect at 17,000 ft as the kick is circulated out. (View > Plot > Pressure at Depth) What is the maximum pressure? Can you still see the curve line for the maximum pressure at 16,131 ft? d) Determine the maximum pressure resulting from the specified influx volume.(View > Plot > Maximum Pressure) Will the casing shoe be able to withstand the maximum pressure resulting from this size of kick?

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e) Would the current casing shoe depth (16,131 ft) suffice if there was a full gas evacuation? (View > Plot > Full Evacuation to Gas) 15. Much of the information required to generate a Kill Sheet can be entered prior to taking a kick. Select Kill Sheet from the Mode drop-down list. Enter the following information to be prepared if a kick should occur. a) Generating a Kill Sheet requires input on the Well Control Setup dialog. Much of this information was input earlier in this exercise. However, slow pump data must also be entered. Please specify the following slow pump information. Pump Name

Speed (spm)

Pressure (psi)

12-P-160

30

400

12-P-160

60

700

b) Specify the use of pump 12-P-160 at 30 spm. Use the Select Pump/Kill Speed button on the (Parameter > Kill Sheet, Pumps Tab). Click Apply. c) Enter the string volume. Use the Default from Editors button (Parameter > Kill Sheet, String Tab). Click Apply. If a string was not entered on the String Editor, you would have to input this information yourself. d) Enter the annulus volume. Use the Default from Editors button (Parameter > Kill Sheet, Annulus Tab). Click Apply. If a string and wellbore were not entered on the String Editor and the Hole Section Editor, you would have to input this information yourself. e) Specify information regarding weighting up the mud. (Parameter > Kill Sheet > Weight Up Tab) The mud tank volume is 800 bbls. Mixing capacity is assumed to be 50 lb/min. Barite is the weighting material used in this example. The specific gravity of barite is 4.2, and is available in 94 lb bags. Click Apply. 16. When a kick is taken, information regarding the kick must be entered on the Parameter > Kill Sheet > Kick Parameters Tab. For this exercise, assume a 25 bbl pit gain at 11,029 ft. The Shut-In Drill Pipe Pressure is 520 psi, the Shut-In Casing Pressure is

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720 psi, the Overkill Pressure is 100 psi, and the Trip Margin is .5 ppg. Click OK to activate your entries and to close the dialog. 17. Use the Kill Sheet report or plot to answer the following questions. a) How many sacks of weighting material will be required to weight up the mud? b) Determine how many strokes are required to fill the string with kill mud? How many minutes will this take? (View > Report > Kill Sheet) c) Determine the standpipe pressure after the string is filled with kill mud. (View > Plot > Kill Sheet)

Answers 1. Double-click on the desired case within the Well Explorer to open it. 2. Click on the Well Control button to select the Well Control module. Select Expected Influx Volume from the Mode dropdown list. 3. Use the Case > Geothermal Gradient tabs. 4. Click the Steady State Circulation button to use that model.

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You do not need to specify the mud density because it defaults from the Case > Fluid Editor.

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5.

a) The Geothermal Gradient profile changes slope because the plot is MD, not TVD. b) The annulus and string curves represent the steady state circulating temperature in the annulus and the string. 6.

The Quick Look section displays the results.

a) A kick while drilling would occur in this situation because the pore pressure is greater than the circulating BHP. b) The difference between the interval pressure where the kick occurred and the static BHP is 274.2 psi. Landmark

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7. Use the Parameter > Influx Volume Estimation tabs to determine the influx volume. a) Use Parameter > Influx Volume Estimation > Kick Detection Method tab to specify the kick detection equipment.

b) Use Parameter > Influx Volume Estimation > Reservoir tab to specify the kick detection equipment.

c) Total crew reaction time is 5.6 minutes. A “hard shut-in” could be modeled by setting some of the reaction times to zero.

Add the reaction times to determine the total crew reaction time.

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d) An 58.3 bbl influx is predicted.

e) A 14.0 bbl influx is predicted when the detection flowrate is reduced to 20 gpm.

8. Select Kick Tolerance from the Mode drop-down list. 9. Use the Case > Circulating System tabs. a) 6000 psi

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b)

Check this box to make the 12-P-160 with 3.702 gal/stk volume the active pump.

10. Use the Case > Well Control Setup > Operational tab to configure some of the analysis options.

11.

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a) The flow rate on this dialog is the average flow rate over the last 24 hours. 12.

The circulation flowrate is the flowrate during drilling just prior to taking the influx. It is not the circulation kill rate.

13.

a) The depth interval to check to reach the casing shoe at 17,968 ft would be 1,837 ft. (17,968 - 16,131) 14. a) The maximum pressure is 12,779.8 psi when 2 bbls have been pumped. The curve does not have a constant slope because it

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reflects the changes in pressure resulting from changing fluid lengths in the different annular sections.

b)

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c) The maximum pressure is 13,462 psi when 2 bbls have been pumped. Yes, you can still see the curve for 16,131 ft.

d)

Yes, the shoe can withstand the kick of 14 bbls.

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e)

The casing shoe could not withstand a full evacuation to gas. 15. Select Kill Sheet from the Mode drop-down list. a) Use Case > Well Control Setup > Slow Pumps to specify slow pump information.

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b)

Click the Select Pump/Kill Speed button to select the pump speed from the dialog that appears.

The Select Pump/Kill Speed dialog appears when the Select Pump/Kill Speed button is clicked.

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c)

Click the Default from Editors button to use the data entered on the Case > String and Case > Hole Section editors.

d)

Click the Default from Editors button to use the data entered on the Case > String and Case > Hole Section editors.

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e)

16.

17. Use the View > Report > Kill Sheet report or the View > Plot > Kill Graph.

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a) Use View > Report > Kill Sheet.

1486.6 sacks are required.

b) 2147 strokes are required to fill the string. It will take 71.6 minutes.

c)

The standpipe pressure is 416 psi.

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Exercise 7: Using Surge Analysis Note Because of class time constraints, we will not be using the low clearance option during the course because of the length of time required to perform the calculations when the low clearance option is used. However, you should consider using this option in the future. The low clearance analysis is an improved analysis model that tightly couples the fluid forces with the axial forces. This analysis option results in more reliable results, particularly when the clearance is less than 0.5 inches and/or the analysis interval is long. The low clearance analysis can take a considerable amount of time to calculate. Therefore, when you use this analysis option, it is recommended that you analyze one operation at a time, and that you limit the analysis to two moving pipe depths.

Steps and Questions 1. Open the Case SRG 11 3/4” Liner. 2. Click the Surge button to start the Surge module. 3. Assume the well has only one formation from the surface to TD. This formation has an Elastic Modulus of 1,500,000 and a Poisson’s Ratio of 0.3. (Case Formation Properties) 4. The cement set behind the casing has an Elastic Modulus of 3,000,000 and a Poisson’s Ratio of 0.35. (Case > Cement Properties) a) Why don’t you specify the cement properties using the Case > Fluid Editor? 5. Use 13.35 ppg OBM. This mud has already been defined. There is no pumping while tripping. 6. Define a surge operation. Name it Run Liner. •

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Specify Depths of Interest to be at 12,834 ft (casing shoe) and at 16,131 ft (TD). Will these depths of interest be used for all operations? You should also analyze any weak formations. Are there any you should consider? WELLPLAN

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•

Assume you want to analyze when the pipe is at the previous casing shoe (12,834 ft), and near TD (use 16,000 ft). You may also want to consider analyzing when the pipe is at the weak zone.

•

To define analysis parameters for this operation, click on the row number for the operation titled Run Liner to highlight the row. Next, click the Details button.

•

Enter a pipe stand length of 90 ft, pipe acceleration of 1 ft/sec2, and pipe deceleration of 1 ft/sec2. Do not use a float. Do not check the Optimize Trip Time box. Why don’t you need to enter a Maximum Trip Speed? (Parameter Operations Data Details Button Analysis Conditions)

•

Specify a pipe speed of 100 ft/min for cased hole and open hole. (Parameter Operations Data Details Button Analysis Depths)

7. Is this operation likely to fracture the formation? 8. To avoid fracturing the formation, you may want to use different trip speeds. Determine the safe tripping speeds using Optimize Trip Time. Use a maximum trip speed of 180 ft/min. 9. You may also want to consider using a diverter sub to avoid fracturing the weak zone. Uncheck the Optimize Trip Time box and add a divertor sub to the workstring. Use the diverter sub in the catalog that has the 0.589 flow area. Does the diverter sub reduce the surge pressure enough to avoid fracturing the weak zone? 10. Define a swab operation. Name it Pull Liner.

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•

Use the same moving pipe depths as you did for the surge analysis.

•

Use the same depths of interest as you did for the surge analysis.

•

To define analysis parameters for this operation, click on the row number for the operation titled Pull Liner to highlight the row. Next, click the Details button.

•

Enter a pipe stand length of 90 ft, pipe acceleration of 1 ft/sec2, and pipe deceleration of 1 ft/sec2. Use a float with zero percent open area. Do not check the Optimize Trip Time box. Why don’t you need to enter a Maximum Trip Speed? (Parameter Operations Data Details Button Analysis Conditions)

•

Specify a pipe speed of 60 ft/min for cased hole and open hole. (Parameter Operations Data Details Button Analysis Depths)

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11. Is this operation likely to cause a kick? 12. Assume the float has a 25% open area. Compare the results for depth of interest 16,131 ft with the float having 0% open area. To easily compare the results, use the Freeze Line feature. After you finish comparing results, right-click on the “frozen” lines and remove them. 13. After the 11 3/4” liner is cemented, is there any problems tripping in, tripping out, or reciprocating the 12 1/4” string used to drill the next hole section? Use the case 12 1/4” Tripping Ops. The surge and swab operations have been defined for you. Define a reciprocation operation. Name it Reciprocate. (Parameter Operations Data) To define analysis parameters for this operation, click on the row number for the operation titled Reciprocate to highlight the row. Next, click the Details button. a) Enter a pipe acceleration of 1 ft/sec2, and pipe deceleration of 1 ft/sec2. Do not check the Float Used in Workstring box. (Parameter Operations Data Details Button Analysis Conditions) b) Specify a Stroke Length of 31 ft, and a Stroke Rate of 5 spm. Use 15.1 ppg OBM with a Flow Rate of 400 gpm. (Parameter Operations Data Details Button Reciprocation Data) 14. Is it likely that these operations will cause any problems over this drilling interval?

Answers 1. Double-click on the case you want to open in the Well Explorer. 2. Click on the Surge button

to select the Surge module.

3. Enter the formation properties based on true vertical depth (TVD). These data are used to calculate the compressibility of the formation.

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4.

a) Because the cement is already set. The Case > Cement Properties dialog is used to specify the properties of set cement. The Case > Fluid Editor is not. 5. Use Case > Fluid Editor to activate the 13.35 ppg WBM if necessary. There is no need to use the Parameter > Job Data dialog because there is no pumping while tripping.

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6. Determine the weak zone by referring to Case > Fracture Gradient.

Notice the weak zone at 13,253 ft vertical depth (not measured depth).

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Define a surge operation using Parameter > Operations Data. Highlight the row and then click Details to input details about the operation.

You don’t need to specify the last casing shoe or TD as a Depth of Interest because they are automatically added.

•

Use Parameter Operations Data Analysis Conditions.

Details Button

You don’t need to specify a maximum trip speed because you are not optimizing trip times.

•

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Use Parameter Operations Data Analysis Depths.

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Details Button

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a) Analysis Depths default from the moving pipe depths specified on the Surge Operations Data dialog. 7. Use View > Single Operation Plot > Transient Response Plot. Use Data Selection to view the results at the weak zone. Yes, it is likely the weak zone will fracture. Notice the surge pressure are predicted to be greater than the fracture pressure at the depth of interest.

8. Check the Optimize Trip Time box on the Analysis Details tab to indicate you want to have WELLPLAN determine the trip speeds to avoid high surge pressures.

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Using the optimized trip time, the pressure no longer exceed the fracture gradient.

Notice the various calculated trip speeds. You would want to use the minimum of these trip speeds to avoid fracturing the weak zone.

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9. Use Case > String Editor to add the diverter sub.

Using a diverter sub, the pressure do not exceed the fracture pressure of the weak zone.

10. Define a swab operation using Parameter > Operations Data. Highlight the row and then click Details to input details about the operation.

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•

Use Parameter Operations Data Analysis Conditions.

Details Button

•

Use Parameter Operations Data Analysis Depths.

Details Button

11. Use View > Single Operation Plot > Transient Response Plot.

Notice that the pressure is very close to the pore pressure at 12,834 ft when the moving pipe is also at that depth.

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Right-click on the plot and use the Data Selection dialog to select the depth of interest to be 13,627 ft.

Notice the pressure is not below the pore pressure at 13,627 at any moving pipe depth.

Right-click on the plot and use the Data Selection dialog to select the depth of interest to be 16131 ft.

Notice the pressure is below the pore pressure at 16,131 ft when the moving pipe is at 13,627 ft and 12,834 ft.

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12.

Using a float with 25% open area significantly reduces the pressure.

13. Use Parameter > Operations Data. To analyze when the bit or bottom of the string is at a certain depth, enter the depth as a Moving Pipe Depth.

8. Use Parameter > Operations Data. Yes, the Depths of Interest are used for all operations.

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9.

Highlight the operation you want to define details for and then click the Details button.

a) The Maximum Trip Speed only applies to operations that will be optimized on trip time. (i.e. those operations that have the Optimize Trip Time box checked.)

b)

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c) Analysis Depths default from the Moving Pipe Depths. (Parameter Operations Data tab) 10. Highlight the operation you want to define details for and then click the Details button.

a)

b)

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11.

Highlight the operation you want to define details for and then click the Details button.

a)

b)

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12. Right-click anywhere on the plot to display the Data Selection dialog. Select Trip In from the list.

Use data reader to read maximum surge pressure at the shoe of 5,326 psi when the bit is at the shoe.

Use Data Reader to determine the pressure.

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13. a)

b)

14. Use View > Multiple Operation Plot > Transient Response to view the pressures for each operation at each depth of interest for each moving pipe depth. Right-click and use Data Selection to select the various moving pipe depth and depth of interest combinations. None of the operations predict pressures likely to fracture the formation or cause a kick.

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Exercise 8: Using Cementing - OptiCem Steps and Questions 1. Open the Case CMT 11 3/4” Liner. 2. Select the Cementing-OptiCem module, and Wellbore Simulator from the Modules menu, or click the Cementing-OptiCem button and select Wellbore Simulator from the Mode dropdown list. 3. Specify a 15% volume excess in the open hole for cement job planning. (Case Hole Section Editor) 4. You will be using the following fluids. Specify or review the fluid data using the Fluid Editor. (Case Fluid Editor) a) Review the properties of the fluid titled 13.35 ppg OBM. b) Type in data for a spacer. Name the spacer 12 ppg Spacer. It is an oil based, Bingham Plastic fluid, with a density of 12 ppg. At 70 deg, the PV is 24, and the YP is 12 lbf/100ft2. c) Type in data for the lead cement. Name the cement 12.5 ppg Lead. It is a Bingham Plastic fluid, with a density of 12.5, a water requirement 12.81 gal/sack, and a yield of 2.12 ft3/sack. At 70 deg, the following Fann data readings apply: at 600 rpm the dial reading is 54.4 deg, at 300 rpm the dial reading is 30.42 deg. d) Type in data for the tail slurry. Name the cement 15.6 Tail. It is a Bingham Plastic fluid, with a density of 15.6, a water requirement 4.98 gal/sack, and a yield of 1.16 ft3/sack. At 95 deg, the following Fann data readings apply: at 300 rpm the dial reading is 150 deg, at 200 rpm the dial reading is 105 deg, and at 100 rpm the dial reading is 59.5 deg. At a temperature of 149 deg the following Fann data readings apply: at 300 rpm the dial reading is 130 deg, at 200 rpm the dial reading is 94.5 deg and at 100 rpm the dial reading is 53.5 deg. At 185 deg, the following Fann data readings apply: at 300 rpm the dial reading is 83 deg, at 200 rpm the dial reading is 57.5 deg and at 100 rpm the dial reading is 31.5 deg.

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5. Copy the fracture gradient data for this case from the case TDA 14 3/4” Hole Section. (Case Frac Gradient) Is there a weak zone? If so, what is the vertical depth at the weak zone? 6. Specify the following cement job data using Parameter Data.

Job

• As the wellbore fluid, use the 13.35 ppg OBM. Pump at a 12 bbl/min rate. • Use 200 bbls of the 12 ppg Spacer as a spacer. Pump the spacer at 8 bbl/min. • Pump the 12.5 ppg Lead cement at a rate of 8 bbl/min. The top of the lead cement should be at 12,534 ft. • Pump 400 ft of the 15.6 Tail slurry at a rate of 4 bbl/min. • Use 80 ft of the tail slurry as the shoe slurry. Pump it at a rate of 4 bbl/min. • Displace the cement with the 13.35 ppg OBM mud pumped at 12 bbl/min. • Use 14.7 psi for the Back Pressure and use 0 bbl Return Volume. • Do not automatically adjust the rates, use foamed cement, or disable auto-displacement calculations. (Don’t check any of these boxes.) • Use the lead cement as the tracer fluid. a) Why are we using 14.7 psi for the back pressure? 7. We will use TD of this hole section (16,131 ft MD) as the reservoir zone of interest and the fracture zone (weak zone) of interest is 13,627 ft MD. Do not take returns at the sea floor. Use a BHCT of 205.3 deg F, a surface temperature of 80 deg F and a mud outlet temperature of 120 deg F. (Parameter Additional Data) 8. Do the circulating pressures during the cement job exceed the fracture pressure? (View Plot Circ Pres and Den - Frac Zone)

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9. Is it possible to take a kick during the cement job or to fracture the weak zone during the job? (View Plot Downhole Pressure Profiles) 10. Does “freefall” occur during the job? (View of Rates In and Out)

Plot

Comparison

11. What is the maximum calculated wellhead surface pressure and when during the job does it occur? (View Plot Calculated Wellhead/Surface Pressure) 12. Using the Fluid Animation Schematic, what is the pressure in the annulus at the bottom of the well when the lead cement gets to the bottom of the liner (when the cement is still inside the pipe)? How many barrels have been pumped when this occurs? (View Fluid Animation Schematic) 13. To reduce the circulating pressures, try using foamed cement. Use a constant flow of gas. Specify the foaming agents to be 2.5% surfactant with no stabilizer. Foam only the cement. Use 9 ppg foam density for all cement and only one segment for each cement stage. 14. Did using foam cement reduce the circulating pressure enough to avoid fracturing the formation? 15. Allow Cementing-Opticem to automatically adjust the cement pump rates in order to avoid the high circulating pressures without using the foamed cement. Use 100 psi safety factor. a) Does this help? b) How were the rates adjusted? (View Rates In and Out)

Plot

Comparison of

c) Does free fall occur?

Answers 1. Using the Well Explorer, double-click on the case name to open it. 2. Click on the Cementing-OptiCem button to select the Cementing application. Select Wellbore Simulator from the Mode drop-down list

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3. Specify a 15% enlarged hole volume here.

4. Use Case > Fluid Editor to define all fluids. a)

Highlight the 13.35 ppg mud and review the properties.

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b) Enter data for the 12 ppg spacer as specified here.

c) Enter data for Lead Cement as specified here.

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d)

Enter data for Tail Slurry as specified here. Notice that this includes Fann data readings at 95 deg.

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Enter data for Tail Slurry as specified here. Notice that this includes Fann data readings at 149 deg. Readings at 185 deg are specified here.

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5. There is a weak zone at 13,253 ft.

6.

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a) When the annulus is to be left open to the atmosphere during the entire job, then 14.7 psi [101 kPa] should be entered for the back pressure value and 0 should be used for the return volume. 7. Do not check this box because we are not taking returns at the sea floor. Enter the zones of interest.

8. Yes, the circulating pressures during the cement job exceed the fracture gradient throughout much of the job.

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9.

Because the minimum hydrostatic is getting very close to the pore pressure, you should consider the possibility of a kick.

It is likely the weak zone may fracture, because the maximum ECD during the job is greater than the fracture pressure of the weak zone.

10.

Because the rates in and out are equal, freefall does not occur.

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11. The maximum wellhead surface pressure is 2135 psi. It occurs when the displacement fluid begins to be pumped.

12.

About 822 bbls have been pumped when the lead cement gets to the bottom.

When 822 bbls have been pumped, the pressure in the annulus at TVD is about 8194 psi.

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13. Be sure to check the Use Foam Schedule box on the Parameter > Job Data dialog. Define foam cement using Parameter > Foam Data.

Click on Lead Cement to specify parameters for that fluid.

Click on Tail Slurry to specify parameters for that fluid.

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14. Use View > Plot > Circ Pres and Den - Frac Zone. Using foamed cement did not reduce the circulating pressure enough to avoid fracturing the formation.

15. Check box to allow software to automatically adjust the pump rates and to use 100 psi safety factor Do not check the Use Foam Schedule box.

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a) Automatically adjusting the rates does keep the circulating pressure below the fracture gradient.

b) All of the pump rates were reduced. The rate is 1 bbl/min.

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c) Free fall occurs. In the previous plot, the rate out exceeds the rate in therefore free fall is occurring.

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Exercise 9: Using Critical Speed Analysis Steps and Questions 1. Open the Case CSA 12 1/4” BHA. 2. Import the template BHA Critical sp.tpt. 3. Select the Critical Speed Analysis module from the Modules menu, or click the Critical Speed Analysis button. Critical Speed Analysis has only one analysis mode so you don’t need to select an analysis mode. 4. Assume the tri-cone bit has 2000 ft-lbs of torque. The weight on the bit is 20 kips. The Steering Tool Orientation is 0 deg. Analyze the drillstring for every two RPM between 0 and 220. Use an Excitation Frequency Factor of 9 for PDC bits. Check the Dynamics box to include the effects of nodal torque due to friction. (Parameter > Analysis Parameters) 5. Review the Boundary Conditions and Mesh Zone set for the analysis, but don’t change them. (Parameter > Boundary Conditions and Parameter > Mesh Zone) 6. Examine the stresses acting on the workstring. a) What rotational speeds may result in high relative stress in the workstring? What is the maximum equivalent stress you can expect? (View > Rotational Speed Plots Resultant Stresses) b) )Where in the workstring are these high stresses likely to occur while rotating at the critical rotational speed? (View > Position Plots Resultant Stresses) c) What type of stress is causing the high equivalent stress? (View > Position Plots Stress Components) d) Explain the difference between the View > Position Plots Stress Components plot and the View > Rotational Speed Stress Components plot. (Hint: Split the window and display each plot in a vertical pane.)

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e) Using the 3D plots, where is the maximum torsional stress in the workstring, and at what rotational speed is it likely to occur? (View > 3D Plots Stress Components Shear) 7. You have been using an Excitation Frequency Factor of 9 which is typical of a PDC bit. Compare the maximum equivalent stresses using the Excitation Frequency Factor of 9 with the maximum equivalent stresses using an Excitation Frequency Factor of 3. (An Excitation Frequency Factor of 3 is typical of roller cone bits.) Hint: Use Freeze Line and View > Rotational Speed Plots Resultant Stresses)

Answers 1. Use the Well Explorer. Double-click the case you want to open. 2. Use File > Workspace > Open Template. 3. Click on the Critical Speed button application.

to start the Critical Speed

4. Use Parameter > Analysis Parameters.

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5. Use Parameter > Boundary Conditions to review the analysis boundary conditions.

Use Parameter > Mesh Zone to review the mesh zone.

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6. Use the plots (using the View menu) to analyze stresses. a) Rotating at 132 and 154 rpm may result in high relative stresses. You can not determine from this plot the actual stresses acting on the BHA. This plot displays relative stresses only. The stress at 132 and 154 rpm is several times greater than the stress at the other rpms, however you can not determine the actual stresses acting on the BHA at these rpms.

Using the Data Reader, you can determine the relative magnitude of the stress at the largest peak.

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b) To determine what component is located at a certain position from the bit, refer to Case String Editor. The high stresses while rotating at 154 rpm are likely to occur in multiple places in the bottom 1100 ft from the bit.

Use the Slider Bar to change the rotational speed.

c) Axial stress is causing the high relative stress while rotating at 154 rpm.

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d)

The View Position Plots Stress Components plot displays the stress components at one rotational speed.

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The View Rotational Speed Stress Components plot displays the stress components for a range of rotational speeds.

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e) The 3D plots work well for gaining general knowledge of what is occurring. If you need specific details, say for distance from bit, you should use a 2D plot. The greatest shear stress occurs here. To rotate the 3D plot, press and hold the left mouse button while moving the mouse. The plot will rotate as you move the mouse.

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7. To use Freeze Line, right-click on the curve you want to freeze. “Frozen” lines remain on the plot when the plot is regenerated using new input data.Change the name, color, and the thickness of the line you freeze so that you can identify it. Relative stress using Excitation Factor of 9.

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Relative stress using Excitation Factor of 3.

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Exercise 10: Using Bottom Hole Assembly Analysis Steps and Questions 1. Open the Case BHA 12 1/4” BHA. 2. Activate the Bottom Hole Assembly analysis by clicking the Bottom Hole Assembly button. 3. Ensure the mesh zone is using default values of 20, 100, and 500 for Aspect Ratios 1, 2, and 3 respectively. Set Length 1 to 500 ft and Length 2 to 2500 ft. 4. The current hole inclination is approximately 0 degrees. We are drilling in a soft formation using 2000 ft-lbs bit torque, 20 kips WOB and rotating at 120 rpm. Drillahead 300 ft. Assume a gauge hole. During the drillahead prediction, record wellpath data every 30 ft. Use a Bit Coefficient of 50, Formation Hardness of 30 and ROP of 25 ft/hr. Check the Dynamics box to include the calculation of nodal torque. Will this BHA build angle? 5. Analyze the position of the BHA in the wellbore and the contact forces acting on it. a) Where is the BHA in contact with the wellbore? (View Displacement) b) What side force is the BHA subjected to? (View Force)

Plot

Plot Side

6. Assume the hole is 1/2 inch overgauge. Does this change the build rate?

Answers 1. Use the Well Explorer to open the case by double-clicking on it. 2. Click on the Bottom Hole Assembly Analysis button select the Bottom Hole Assembly application.

to

3. Use Parameter > Mesh Zone.

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4.

Be sure to check the Enable Drillahead box to predict how the BHA will perform over the Drill Interval specified.

Very slight build.

5. a)

The BHA contacts the wellbore when the clearance is zero.

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b)

6.

An overgauge hole slightly increases the build rate.

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Exercise 11: Using Stuck Pipe Analysis Steps and Questions 1. Open the Case STU 12 1/4” BHA. 2. Select the Stuck Pipe application and Stuck Point Analysis from the Modules menu, or click the Stuck Pipe button and select Stuck Point Analysis from the Mode drop-down list. 3. Setup the analysis parameters (Case > Stuck Pipe Setup Data). The traveling assembly weight is 50 kips. Do not include sheave friction correction. Use 90% of the effective yield to determine maximum overpull. Click OK. 4. Determine the location of the stuck point. Assume you were tripping out when the string became stuck. The initial load of the stretch test was 525 kips and the final load was 600 kips. The stretch was 74 inches. What is the stuck point? 5. Specify the jar operating forces. The up and down set forces are 1 kip. The pump open force is 11 kips, the up trip force is 90 kips and the down trip force is 40 kips. 6. Determine the surface actions to set and trip the jar. The measured weight when stuck is 433 kips. The jars fire downwards and there is no circulation while jarring. What is the measured weight required to trip the jar? What is the measured weight required to reset the jar? 7. Will the loads required to set, trip and reset the jar cause the string to fail? 8. What surface actions are required to backoff at 17,200 ft MD? To backoff, place the stuck point slightly in tension (1 kip) and apply 1,000 ft-lbs of torque.

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Answers 1. Using the Well Explorer, double-click on the case to open it. 2. Click on the Stuck Pipe button to select the Stuck Pipe application. Select Stuck Point Analysis from the Mode dropdown list. 3.

4. Use Parameter > Analysis.

The stuck point is at 17,288 ft MD.

5. Use the String Jar Data dialog to specify the jar operating parameters. To access the String Jar Data dialog, double-click on a

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non-editable field associated with the jar on the Case > String Editor.

6. Select Jar Analysis from the Mode drop-down list. Use Parameter > Analysis to determine the required surface action to activate the jar. The measured weight required to trip the jar.

The measured weight required to reset the jar.

7. Select Yield Analysis from the Mode drop-down list. Use Parameter > Analysis to determine if the measured weights

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required to set (432 kips), trip (281.2 kips) and reset (322.2 kips) the jars will yield the string.

Although the string buckles, it will not fail using the required measured weights.

8. Select Backoff Analysis from the Mode drop-down list. Use Parameter > Analysis to determine the surface actions required.

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Exercise 12: Using Notebook Steps and Questions 1. Open the Case NBK 12 1/4” BHA, and launch the Notebook module from the toolbar, or using Modules > Notebook. All of the Notebook analysis modes can be selected from the Mode drop down list, and any of the calculations in that Mode can be launched from the Wizard list. Alternatively any of the analysis Modes can be chosen by using Modules > Notebook and the Calculation can be accessed from the Parameter menu. For simplicity, we will use the Mode and Wizard lists for this exercise. 2. Select Hydraulics from the Mode drop down list. a) Select Pump Output from the Wizard list. Enter the following information for a triplex pump. Stoke = 6.5 in, Vol. Efficiency = 95%, Stroke Rate = 150 spm, and Liner Diameter = 11 inch. Observe the results. b) Use the Wizard list to select Annular and enter the following general input for Section 1. Flow Rate = 400 gpm, Hole Diameter = 9.625 in, Pipe Diameter = 5 in, and Length = 1000 ft. Although two sections can be calculated simultaneously, enter zeros into the input for Section 2. Observe the results. c) From the Wizard list, select Pipe, and enter the following data for Section 1. Flow Rate = 400 gpm, Pipe OD = 5 inch, Pipe ID = 4.5 inch, Length = 900 ft. For Section 2 enter: Pipe OD = 7.75 in, Pipe ID = 2.25 in, Length = 100 ft. Observe the results. d) From the Wizard list, select Nozzle Area. Select the Total Flow Area option and enter the following nozzle sizes to determine the TFA. Use wo 16/32, one 15/32 and one 14/32. e) Select Fluid Buoyancy from the Wizard list to calculate the buoyancy factor for a given mud weight. Enter a mud weight of 10 ppg. Observe the results. 3. Select Fluids from the Mode drop down list. a) From the Wizard list, select Mix Fluids to calculate the final volume and density of two combined fluids. Enter: Volume 1 =

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WELLPLAN Exercises

400 bbls, Density 1 = 9.7 ppg, Volume 2 = 100 bbls, and Density 2 = 8.33 ppg. Observe the results. b) Select Dilute/Weight Up Fluid from the Wizard list to calculate the resulting volume when the density of a fluid is increased or decreased. You may opt to keep the Total Volume constant. For this exercise, use: Initial Volume = 3000 bbls, Initial Density = 9.7 ppg, Required Density = 10.5 ppg, and Mix Fluid Density = 12 ppg. Do not check the Maintain Total Volume option. Observe the results. c) Select Fluid Compressibility from the Wizard list to calculate the volume pumped to overcome the compressibility of the fluid. You can select between WBM and OBM. For this exercise, use: Hole Volume = 1200 bbl, and Test Pressure = 1000 psi. Perform the calculations once for water based mud, and again for oil based mud. It is obvious that OBM is more compressible than the WBM. As a result of the higher compressibility of the OBM, a greater volume of OBM is pumped. 4. Select Miscellaneous from the Mode drop down list. a) Select Linear Weight from the Wizard list. This options calculates the linear weight in air and the buoyed weight of a section of pipe or casing. Use the following input data: Outer Diameter = 7 in, Inner Diameter = 6.276 in, Length = 3,700 ft, Mud Weight = 9.7 ppg and Steel as the material type. Observe the results. b) From the Wizard drop down list, select Blockline Cut Off Length to calculate the recommended cut-off length for rotary drilling lines. As the Drum Type, Mast Height, and Drum Diameter are defined, the Cut Off amount is displayed. For this exercise, use Counter Balanced Drum, Mast Height of >161 ft, and Drum Diameter of 36 in. Observe the results. c) From the Wizard list, select Leak Off Test to determine the formation breakdown pressure, equivalent mud gradient, and formation breakdown gradient based on the leak off test data. Enter the following data: MW = 9.7 ppg, Test Pressure = 1000 psi, TVD = 4,500 ft, Air Gap = 100 ft, and Sea Depth = 300 ft. Observe the results. 5. Select Analysis from the Mode drop-down list.

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WELLPLAN

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WELLPLAN Exercises

a) Select Parameter > Workstring > Maximum String Length. Specify a 100 kip Overpull. In a vertical well, how long could the string be before it failed under its own weight? b) Select Parameter > Workstring > Weight. The current measured depth is 15,000 ft and the mud weight is 15 ppg. What is the buoyed string weight and the weight in air? c) Select Parameter > Workstring > Elongation. What is the string elongation when 100 kips is applied when the bit is at 15,000 ft in 15 ppg mud? d) Select Parameter > Volumes/Heights. What is the volume of fluid in the string between 1,000 and 12,000 ft? e) Select Parameter > Lag Times. How many strokes are required to circulate a sample for depths between 4500 ft and 5,000 ft? Calculate using a 100 ft increment. Click the Pump Equipment button to specify pump details of your choosing. f) Select Parameter > Spot a Pill. If you want the bottom of a pill to be at 10,000 ft, how much volume do you need to displace? g) Use Parameter > Block Line Work to calculate the block line work for drilling using data of your choosing. h) Use Parameter > Rig Capacity to determine the loads applied to the rig while drilling and/or tripping using data of your choosing.

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WELLPLAN

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