WellFlo User Guide 20090130

WellFlo™

Petroleum Engineering Software

User Guide

Software Version 4.0

We l l F l o TM USER GUIDE Software Version: 4.0

COPYRIGHT AND WARRANTY WellFlo 4.0 © 2009 Weatherford International This document contains information proprietary to Weatherford International, with all rights reserved worldwide. Any reproduction or disclosure of this publication, or any part hereof, to persons other than Weatherford International personnel is strictly prohibited, except by written permission of Weatherford International.

DISCLAIMER Information in this guide is subject to change without notice and does not constitute a commitment on the part of Weatherford International. It is supplied on an “as is” basis without any warranty of any kind, either explicit or implied. Information may be changed or updated in this guide at any time.

THIRD-PARTY SOFTWARE The following products and organizations have been mentioned in this documentation. Various trademarks are owned by the respective owners. Microsoft®, Windows 95®, Windows 98®, Windows 2000®, Windows NT® and Windows XP® are either registered trademarks or trademarks of Microsoft Corporation in the United States and/or other countries, http://www.microsoft.com.

USING THIS MANUAL This manual is designed to address the needs of both the new and advanced user. It assumes you have knowledge of basic oil field terminology and have minimal familiarity with Microsoft Windows®.

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CONTENTS

SECTION I: GETTING STARTED CHAPTER 1: Overview .................................................................................................................................. 11 Introduction ................................................................................................................................................. 13 System Requirements ................................................................................................... 13 Deliverability Applications .......................................................................................... 14 Diagnostic Applications ............................................................................................... 15 WellFlo Interface ......................................................................................................................................... 16 Configuring Preferences .............................................................................................. 18 Charts .............................................................................................................................. 21 Tables .............................................................................................................................. 24 Importing Data from an External Source .................................................................. 25 Units Editor ................................................................................................................................................... 27 Unit System Terminology and Rules .......................................................................... 28 Configuring Units ......................................................................................................... 29 Conversions ................................................................................................................... 31 Multi-lingual Support ............................................................................................................................... 33 Downloading a Dictionary from the Weatherford Website .................................... 33 Adding a New Dictionary ........................................................................................... 35 Adding a Dictionary from an Existing File ............................................................... 37 Creating A WellFlo 4.0 Dictionary .............................................................................. 40 Applying a Different Installed Language .................................................................. 43 Setting-Up and Running a WellFlo Model ......................................................................................... 44 Configuration ................................................................................................................ 45 Analysis .......................................................................................................................... 46 Design ............................................................................................................................. 46 Output ............................................................................................................................. 47 Use of Depths and Deviations ............................................................................................................... 47 Depth Conventions ....................................................................................................... 48 System Description and Data Files ...................................................................................................... 52 WellFlo Data Files ......................................................................................................... 52

WellFlo | User Guide

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CONTENTS

SECTION II: CONFIGURATION CHAPTER 2: Configuration ......................................................................................................................... 55 Configuration .............................................................................................................................................. 56 General Data ................................................................................................................................................ 58 Well and Flow Type ................................................................................................................................... 60 Flow Correlations ....................................................................................................................................... 65 Reference Depths ...................................................................................................................................... 71 Fluid Parameters ........................................................................................................................................ 73 Tuning PVT Models ................................................................................................................................... 86 Wellbore Deviation .................................................................................................................................... 96 Example: Entering New Rows of Data ..................................................................... 99 Example: Editing Existing Rows of Data ................................................................ 101 Wellbore Equipment ............................................................................................................................... 102 Adding Tubing ........................................................................................................... 102 Adding Casing ............................................................................................................ 104 Adding Restrictions ................................................................................................... 106 Adding Trace Points ................................................................................................... 108 Surface Terrain Data ................................................................................................................................ 110 Surface Equipment .................................................................................................................................. 114 References .................................................................................................................................................. 127 CHAPTER 3: Reservoir Layers ................................................................................................................... 129 Reservoir Layers ........................................................................................................................................ 130 Setting General Parameters ....................................................................................... 131 Segmented IPR Model ............................................................................................... 138 Configuring Drainage Geometry ............................................................................. 140 Plotting IPR/IIR ........................................................................................................... 149 Adding to Plots ........................................................................................................... 151 Plotting Composite IPR ............................................................................................. 153 Relative Permeability ................................................................................................. 157 Skin Analysis .............................................................................................................................................. 167 Skin Analysis: Completion (Vertical) ...................................................................... 167 Calculations (Vertical) ............................................................................................... 173 Skin Analysis: Completion (Horizontal) ................................................................. 175 Calculations (Horizontal) .......................................................................................... 180 Skin Analysis: Completion (Fractured) ................................................................... 183 Calculations (Fractured) ............................................................................................ 189 References .................................................................................................................................................. 190

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CHAPTER 4: Temperature Model ............................................................................................................ 193 Temperature Model ................................................................................................................................. 194 Calculation Methods .................................................................................................. 194 Configuring a Temperature Model .......................................................................... 197 References .................................................................................................................................................. 206

SECTION III: ANALYSIS CHAPTER 5: Analysis ................................................................................................................................... 209 Analysis ........................................................................................................................................................ 210 Operating Conditions ............................................................................................................................. 210 Setting Operating Conditions ................................................................................... 212 Sensitivities ................................................................................................................................................. 218 Creating and Editing Sensitivities ............................................................................ 218 Running Sensitivities .................................................................................................. 220 Temperature Sensitivity to Elapsed Time ................................................................ 223 Export ........................................................................................................................................................... 224 Exporting Files in VFP, BHP and Other Formats ................................................... 224 Flowing Pressure File Output ................................................................................... 228 L‐Factor and Flow Correlation Tables ...................................................................... 228 Reports ......................................................................................................................................................... 232 Critical Unloading Rate .......................................................................................................................... 233 Pressure Drop Correlations ................................................................................................................... 235 Pressure Drop Through a Restriction ................................................................................................ 240 Surface Chokes ............................................................................................................ 240 Sub‐Surface Restrictions ............................................................................................. 242 ANALYSIS.log ............................................................................................................................................. 242 Flow Regime Numbers .............................................................................................. 244 EPS Mechanistic Correlations ................................................................................... 245 References .................................................................................................................................................. 246

SECTION IV: ARTIFICIAL LIFT CHAPTER 6: ESP ............................................................................................................................................ 251 WellFlo ESP Overview ............................................................................................................................. 252


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CONTENTS

ESP Design and Analysis Overview ................................................................................................... 253 Designing an ESP Installation .................................................................................. 253 Analyzing an ESP Installation .................................................................................. 254 ESP Data Configuration ......................................................................................................................... 255 Pump Environment — Design Mode ...................................................................... 256 Wear Factors and Efficiencies ................................................................................... 258 Pump Calculation Options ....................................................................................... 261 ESP Analysis Mode ................................................................................................................................... 264 Pump Environment — Analysis Mode ................................................................... 265 Selecting Analysis Equipment .................................................................................. 265 ESP Pump and Motor Files .................................................................................................................... 269 Editing esppump.dat ................................................................................................. 269 Editing espmotor.dat ................................................................................................. 271 ESP Design .................................................................................................................................................. 273 Optimizing Pump Performance ............................................................................... 275 Vary Depth ................................................................................................................................................. 280 Plotting and Reporting .............................................................................................. 282 References .................................................................................................................................................. 282 CHAPTER 7: Gas Lift .................................................................................................................................... 283 Gas Lift Data Configuration .................................................................................................................. 284 Gas Lift Design .......................................................................................................................................... 289 Sizing ............................................................................................................................ 317 True Valve Performance ............................................................................................ 318 IPO Valves ................................................................................................................... 320 PPO Valves .................................................................................................................. 321 Spring‐Operated Valves ............................................................................................ 323 Orifice Valves .............................................................................................................. 323 Design Computations ................................................................................................ 323 Sample Gas‐Lift Plots ................................................................................................ 326 Order Form .................................................................................................................. 328 Design Parameters Report ........................................................................................ 329 Tubing Load Requirements Report ......................................................................... 330 Design Calculations Report ...................................................................................... 331 Tubing Requirements Plot ........................................................................................ 332 References .................................................................................................................................................. 334

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CONTENTS

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APPENDIX A: Tutorial 1 ............................................................................................................................... 335 Introduction and Objectives ...................................................................................... 335 Sensitivity Analysis and Results ............................................................................... 337 Plotting ......................................................................................................................... 340 APPENDIX B: Tutorial 2 ............................................................................................................................... 349 Introduction ................................................................................................................. 349 Condensate Fluid Characterization .......................................................................... 349 Sensitivity Analysis and Results ............................................................................... 352 Plotting ......................................................................................................................... 355 APPENDIX C: Tutorial 3 ............................................................................................................................... 363 Introduction ................................................................................................................. 363 Inflow Performance .................................................................................................... 363 Semi‐steady State Inflow Performance .................................................................... 364


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CONTENTS


SECTION I GETTING STARTED

This section provides an introduction to the WellFlo system, including navigating the system, working with data files and setting up and running a well model. CHAPTER 1 Overview .......................................................................................... 11

Chapter 1 OVERVIEW This chapter gives an overview of WellFlo and describes its basic features. This chapter also describes the WellFlo interface and how to use it to set up and run a WellFlo model, including well configuration, tuning, analysis and results. Finally, this chapter explains the depth conventions and data files. Introduction ...................................................................................... 13 System Requirements .................................................................. 13 Deliverability Applications ......................................................... 14 Diagnostic Applications .............................................................. 15 WellFlo Interface .............................................................................. 16 Configuring Preferences ............................................................. 18 Charts ............................................................................................. 21 Tables ............................................................................................. 24 Units Editor ...................................................................................... 27 Unit System Terminology and Rules ........................................ 28 Configuring Units ........................................................................ 29 Conversions .................................................................................. 31 Multi‐lingual Support ..................................................................... 33 Downloading a Dictionary from the Weatherford Website ... 33 Adding a New Dictionary .......................................................... 35 Adding a Dictionary from an Existing File .............................. 37 Creating A WellFlo 4.0 Dictionary ............................................. 40 Applying a Different Installed Language ................................. 43 Setting‐Up and Running a WellFlo Model .................................. 44 Configuration ............................................................................... 45 Analysis ......................................................................................... 46 Design ............................................................................................ 46 Output ........................................................................................... 47 Use of Depths and Deviations ....................................................... 47 Depth Conventions ...................................................................... 48


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OVERVIEW

System Description and Data Files ............................................... 52

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User Guide | WellFlo

OVERVIEW Introduction

INTRODUCTION WellFlo is a Nodal Analysis program designed to analyze the behavior of petroleum fluids in wells. This behavior is modeled in terms of the pressure and temperature of the fluids, as a function of flow rate and fluid properties. The program takes descriptions of the reservoir, the well completion (i.e. the hardware within the well), and the surface hardware (i.e. pipelines etc.), combined with fluid properties data. The program then performs calculations to determine the pressure and temperature of the fluids. Different modes of operation can be employed to either solve for flow rate given controlling pressures (typically deliverability calculations), or solving for pressure drops given measured flow rates (typically diagnostic calculations).

System Requirements The following system requirements must be met before installing WellFlo: •

Operating System: XP professional

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Processor: 1 GHz 32‐bit (x86)

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System Memory: 512 MB of

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Hard Disk: 60 GB hard drive with at least 15 GB of available space

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Graphics Card: Support for DirectX 9 graphics and 32 MB of graphics memory

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Display Mode: 1024 x 768


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OVERVIEW Deliverability Applications

Deliverability Applications

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•

Calculating the Flow Potential (or Deliverability) of a Well: This requires a particular form of nodal analysis. The calculation cannot be made directly, so a technique for determining the Operating Point is used, whereby the Pressures at a point (i.e. Node) in the system are calculated for a range of Flow Rates, by calculating downwards from the top of the system and upwards from the bottom. Only one Flow Rate will provide the same Pressure at the solution Node calculated in both directions ‐ this is obtained from an intersection of curves. This Flow Rate and the corresponding Pressure determine the Operating Point of the system.

•

Designing the Completion of a Well: This is an extension of the previous application, where deliverability can be calculated as a function of different sizes of tubing, different perforations, etc., allowing the optimum completion to be chosen, given that a more expensive completion must justify itself in terms of higher production. Design facilities also include gas lift parameters like valve positioning, valve sizing and setting, and ESP selection.

•

Modeling the Sensitivity of a Well Design to Different Factors That May Affect it in the Longer Term: These factors may include increasing water production or decreasing reservoir pressure. Sensitivity modeling may encompass the reservoir, well, surface configuration, or the operating conditions.


OVERVIEW Diagnostic Applications

Diagnostic Applications This alternative mode of calculation is simpler: this is where the flow rate is known and the pressure at one point is required, given the pressure at another point. This is useful for the following reasons: •

Comparing measured and calculated data, which could be for one of several purposes, such as evaluating the best flow correlation within WellFlo, evaluating Match Parameters, which are impossible to measure, such as pipe roughness, or determining if a well is behaving as it is expected to (i.e. to detect faulty components).

•

Monitoring work, such as predicting reservoir pressure from measured surface pressure and flow rate. This will enable the engineer to see if the system is behaving as predicted, even though they may not be able to measure all parameters at one time. This contrasts with the above application, where diagnostics are done by comparing measured and calculated data.

•

Design work where it is required to calculate the pressure drop in a system (e.g. to determine whether a given system will be able to flow to surface and still leave enough pressure to operate surface equipment). Optional facilities also are available to select ESPs and motors appropriate to the conditions specified, or to space out and size Gas‐Lift valves.


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OVERVIEW WellFlo Interface

WELLFLO INTERFACE The main WellFlo window (see Figure 1‐1) contains a Navigation pane and a Workbench. The Navigator is the pane on the far left of the application window. Use this pane to navigate the system and open the main program menus. The Workbench is the main content pane with which you interact with the system. When a file is opened initially, the current Dashboard configuration for that file is shown in the Workbench. Open each of the following menus through the Navigator: •

Configuration. Allows you to enter all data necessary to create a well model, including the well and flow type, flow correlations, reference depths, fluid parameters, reservoir layers data, wellbore and surface equipment, and specific artificial lift type data.

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Analysis. Allows you to perform various nodal analysis tasks, such as calculating flow curves and performing operating point and pressure drop calculations. You also can export data through the Analysis menu.

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Design. This menu is enabled only if WellFlo‐ESP or Gas Lift is installed

and is used for designing ESP and Gas Lift applications. •

Output. Allows you to load previous saved data without having to re‐run

the calculations. For more information, see “Output” on page 47.

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OVERVIEW WellFlo Interface Figure 1-1: WellFlo Main Window

Most WellFlo windows share the following screen properties: •

Pin. Many of the windows and charts can each be pinned (docked) or

unpinned (floating). By default, all windows are pinned. Click the pin icon to unpin a window so that it can be moved freely. Unpinned windows appear slightly transparent and remain in the forefront of your screen, even when the application is minimized or set to the background. Click the pin icon again to re‐pin the window in the application. •

Shrink or Expand. Many of the windows can be shrunken (reduced) or expanded (restored). This toggle button shows two arrows pointing upward when the window is expanded. Click the two upward‐facing arrows to Shrink the window. The toggle button shows two arrows pointing downward when the window is shrunken; click these two downward‐facing arrows to Expand the window to its original size.

•

Dock to Layout. Many of the windows can be opened in the Layout Manager, which allows you to adjust the appearance of the window. Click Dock to Layout to open a window in the Layout Manager.


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OVERVIEW Configuring Preferences

If you have worked within WellFlo previously and begun or completed a well model, the following Getting Started screen will appear when the application is started (see Figure 1‐2). Figure 1-2: WellFlo Getting Started

This page lists the most recent saved models and the date and time they were last modified. Click a model name from the list to resume your work on that model. You also can open recent well models by going to File > Recent Files... and selecting a model from the list. Go to File > Open to access other existing well models not listed. You can perform these File menu tasks by clicking the shortcuts in the Project Tasks section in the task bar on the left side of your screen.

Configuring Preferences Application Options, in the Settings menu, are used to set‐up individual user preferences for various options within WellFlo. You can configure default values for various properties and model constants, set the actions for automatically loading and saving files and configure the output options for logging application data.

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TO CONFIGURE APPLICATION OPTIONS: 1 On the WellFlo application toolbar, select Settings > Options... The Application Options dialog box is displayed (see Figure 1‐3). Figure 1-3: Application Options

2 To edit any of the Model Constants, double‐click in the value fields and enter new data. 3 Select Settings, under Preferences. The Settings configuration screen is displayed (see Figure 1‐4).


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Figure 1-4: Application Options - Logging

4 Select the directory to designate as the default for WellFlo Data Files (*.LOG) in the Logging Folder field. 5 Check Output to WellFlo.Log to output a textual description of the last Nodal Analysis Calculation in ASCII format. It can be viewed externally with a text editor. 6 Check Output to Analysis.Log to output a detailed numerical description of the last Nodal Analysis Calculation. The file is tab‐separated, and is best viewed with a spreadsheet program such as Excel, or printed out. It also can be viewed (although not so conveniently) with a text editor. The Analysis.Log contains the values of over 20 different variables at each Calculation Point in a Nodal Analysis run.

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Successive runs are appended to the existing WellFlo.Log or Analysis.Log, unless the Clear .Log every run option is checked.

Users are advised to keep the Clear .Log every run option checked (except for special circumstances), since the *.Log files can become very large.


OVERVIEW Charts

7 Select Default Values, under Preferences. The Default Values configuration screen is displayed (see Figure 1‐5). Figure 1-5: Application Options - Default Values

8 Select a property category through the Category Filter drop‐down list to narrow down the list of properties shown in the dialog box. 9 Edit the default values by double‐clicking in the white fields and entering new data. 10 Click OK to close the dialog box.

Charts WellFlo charts contain standard toolbar options that allow you to manipulate the appearance of the chart. You can access many of the chart functions by right‐clicking anywhere within the chart. Mousing over a chart series highlights that series and brings it to the forefront of the chart, while fading and sending all other series to the background. Clicking or mousing over a point in a chart series brings up a flagged description of that point’s specific value and X and Y coordinates. A sample chart is displayed in Figure 1‐6.


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OVERVIEW Charts

Figure 1-6: Sample Chart

The chart toolbar provides the following buttons: Copy to Clipboard: Copies the contents of the active chart in a user-specified format (bitmap, metafile or text only) to the clipboard for pasting into other applications. Print: Prints a copy of the active chart. Gallery: Gives you the choice of chart type and automatically updates the active chart based on your selection. Anti-Aliasing: Toggles between smooth data series lines and jagged curved or diagonal lines.

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OVERVIEW Charts

Palette Selector: Allows you to select from among sets of different color palettes to apply to the chart. 3D/2D: Toggles the data series' image between 2-dimensional and 3-dimensional options. Rotated View: Toggles the chart between standard and rotated view. (Rotated View is available only when the active chart is in 3D mode.) Rotate Around Y Axis: Rotates the chart incrementally around the Y-axis. (Rotate Around Y Axis is available only when the active chart is in Rotated View.) Rotate Around X Axis: Rotates the chart incrementally around the X-axis (Rotate Around X Axis is available only when the active chart is in Rotated View.) Clustered (Z-Axis): Automatically moves the densely-populated area into the background when used with a densely-populated chart, which aids in viewing and interpreting the chart. Axes Settings: Allows you to overlay a vertical grid (based upon the X-axis) or horizontal grid (based upon the Y-axis) onto the chart. The Axes Settings Options opens the axes settings tab in the Properties dialog box. Point Labels: Displays or hides the values of data points on the graph. Data Editor: Displays or hides all of the data used to generate the chart. The data appears in a table below the chart. To edit data in the table, double-click on the desired cell. The column title also can be edited by double-clicking on it, which changes the series name in the legend box. You can right-click in the Data Editor and select Left, Top, Right or Bottom to relocate the table. Legend Box: Displays or hides the legend. By default, the legend box is placed at the right of the chart. To select another location, right-click on the legend and select Left, Top or Bottom. The legend box is automatically re-positioned. Zoom: Magnifies a user-specified area of the chart. After selecting this option, move the mouse pointer to the area of interest, and click and drag the box that appears to define the zoom area. Release the mouse button to see the magnified section of the graph. Select Zoom again to return the graph to its normal state.


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OVERVIEW Tables

Properties: Opens the chart Properties dialog box. General, Series and Axes tabs let you modify chart characteristics. When finished, click Apply and then OK to close the dialog box.

Charts files can be saved in the following formats: *.bmp, *.gif, *.png or *.jpeg.

Tables WellFlo tables contain standard toolbar options that allow you to add and delete rows or columns, transpose the orientation of the table, or import data from a catalog or external source. A sample table is displayed in Figure 1‐7. Figure 1-7: Sample Table

The table toolbar provides the following buttons: Transpose grid: Converts the table orientation from horizontal to vertical, or vice versa. Add a new row: Adds an additional row after the last row in the table. Insert a row before the current row: Adds a new row before the selected row. Delete current row: Removes the selected row. Add or remove columns: Opens the Add or Remove Columns dialog box., which allows you to select which columns to show or hide from the table. You also can change the column order by selecting a column name and clicking Move Up or Move Down to change its position. Click Apply to set your changes.

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OVERVIEW Importing Data from an External Source

Import data from external source: Opens the Data Import Wizard, which allows you to configure the data import process. WellFlo allows you to import data from Excel spreadsheets, text files, Web Services or SQL Server databases. For more information, see “Importing Data from an External Source” on page 25. Select row data from catalog: Allows you to import row data from a manufacturer’s catalog.

Importing Data from an External Source WellFlo allows you to import data from Excel spreadsheets. You can copy and paste data from Excel files into WellFlo tables or you can import the data using the Data Import Wizard. You also can copy and paste a chart series between WellFlo and an Excel spreadsheet.

TO IMPORT WITH THE DATA IMPORT WIZARD: 1 Open the WellFlo table to which you want to add data. 2 Click the Add a new row button to add an empty row to the table.

Add a new row: Adds an additional row after the last row in the table.

3 Click the Import data from an external source button to open the Data Import Wizard. Import data from external source: Opens the Data Import Wizard, which allows you to configure the data import process.

The Data Import Wizard is launched and an Open dialog box is displayed. 4 Browse and select the file whose data you want to import, and click Open. 5 If the selected Excel file contains more than one Worksheet, select the Worksheet that you want to import. 6 Click Next.


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OVERVIEW Importing Data from an External Source

7 Enter the row number that contains the column description, then enter the row numbers at which to start and end data import (see Figure 1‐8). Figure 1-8: Import Wizard - Column Selection

8 Click Next. 9 Select the Source Columns associated with the Destination Columns (see Figure 1‐9).

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If a source column is unavailable, uncheck Available.

10 Select the Source Unit type.

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OVERVIEW Units Editor

Figure 1-9: Import Wizard - Destination Columns

11 Click Next. A preview table is displayed, based on your configurations. 12 Click Finish to import the data, or click Back to re‐configure it.

UNITS EDITOR The Units Editor contains a list of unit Systems that are currently available, including supplied and any customized (i.e. user‐created) unit Systems. The Units Editor is used to select and switch to an alternative units System from the currently selected (i.e. highlighted) unit System. It also can be used to create new unit Systems or delete any customized (i.e. user‐created) systems. The Units Editor can be used to create customized Unit Systems based on copies of the existing systems in the WellFlo database. Standard sets of Oilfield Units and SI Units are supplied with WellFlo. These supplied sets can act as a base for creating and editing customized unit Systems.


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OVERVIEW Unit System Terminology and Rules

Unit System Terminology and Rules It is important that users understand the terminology and associated rules within the Units Editor. Terms: •

Unit. A Unit of measurement (e.g. ft).

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Unit Class. A generic name describing the parameter type or class being measured (e.g. Length).

•

Unit System. The complete set of Units assigned, consisting of a Unit for each field name (e.g. the Oilfield Units System, SI (Canada) System, etc.).

•

Standard Unit. One Unit in each Unit Class that cannot be edited and comes supplied with the system (e.g. ft in the Length class, psia within the Pressure class).

Rules: 1 A field name can only be in one Unit Class (e.g. Measured Depth is in the Length class). 2 Only one Unit in a Unit Class can be assigned to each data Field Name (e.g. Measured Depth can (obviously) not be in feet and meters at the same time). However, different Units can be assigned to different data Field Names from the same Unit Class (e.g. Wellbore Radius and Measured Depth both have Units from the Length class, but one could be assigned in inches, the other in feet, meters, etc.). 3 Each Unit Class contains one uneditable Standard Unit. Other Units can be derived from this and added to the Unit Class. The exception to this is the Unit Class called None. This Unit Class contains dimensionless Units that are not usually assigned a data Field Name (e.g. Skin Factors, Penetration Ratio, etc.). 4 The Unit Systems supplied with WellFlo are locked and cannot be altered. However, they can be copied and altered under a new name. Users can then build their own customized Units System by editing or defining new Units.

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OVERVIEW Configuring Units

Configuring Units Standard sets of Oilfield Units and SI Units are supplied with WellFlo. These supplied sets cannot be altered, but copies can be made and edited to create a customized unit System; these customized copies can be subsequently edited and deleted.

TO CONFIGURE UNITS: 1 On the WellFlo application toolbar, select Settings > Units > Units... The Units Editor is displayed (see Figure 1‐10). Figure 1-10: Units Editor

The System highlighted is the one currently active. 2 Select another system and click OK. The units of measurement assigned within the newly‐selected system will be used throughout WellFlo. 3 Select a customized System and click Delete System to delete a previously created system. You cannot delete supplied Systems.


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OVERVIEW Configuring Units

4 To create a custom System, click New System. The Create New Unit System dialog box is displayed (see Figure 1‐11). Figure 1-11: Create New System

5 Enter a name for the new system and select a supplied system on which to base the new system. This selection provides a source Unit System for customization. WellFlo is supplied with a standard set of default values for each supplied unit System, and any user‐defined unit System is automatically associated with the standard set of defaults derived from the source unit System used to create it. 6 Click OK. The new system is added to the list of available Systems in the Units Editor. 7 To customize your new system, select it in the Units Editor. Select a unit type and set the default value by selecting it from the Default Unit drop‐down list (see Figure 1‐12).

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OVERVIEW Conversions Figure 1-12: Units Editor - Custom System

8 Click Apply to save your settings.

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To delete a custom unit System, select the system in the Units Editor, and click Delete System.

9 Click Use Default Settings to load the default settings. This returns the Systems available in the Units Editor to their original default state by removing any custom Systems and adding any deleted supplied Systems. 10 Click OK to close the Units Editor.

Conversions These supplied sets cannot be altered, but copies can be made and edited to create a customized unit System; these customized copies can be subsequently edited and deleted.


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OVERVIEW Conversions

TO CONFIGURE CONVERSIONS: 1 On the WellFlo application toolbar, select Settings > Units > Units... 2 Open the Conversions tab. The Conversions configuration screen is displayed (see Figure 1‐13). Figure 1-13: Units Editor - Conversions

3 Select a Unit Type and Conversion from the menus to open its conversion configuration screen. 4 Click OK. 5 Edit the new conversion through its conversion configuration screen, and click Apply to save your changes.

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To delete a conversion, select it from the menu and click Delete Conversion.


OVERVIEW Multi-lingual Support

Unit Calculator WellFlo contains a Unit Calculator for calculating between two units. To access the Unit Calculator, go to Settings > Units > Unit Calculator (see Figure 1‐14). Figure 1-14: Unit Calculator

Select the unit type from the drop‐down list. Then select the two units on which to perform calculations.

MULTI-LINGUAL SUPPORT WellFlo 4.0 comes with a very versatile support for multiple languages. You can select from a built‐in set of languages or download dictionaries from Weatherfordʹs website directly from the application via the Settings > Language... menu item.

Downloading a Dictionary from the Weatherford Website TO DOWNLOAD A DICTIONARY: 1 Open WellFlo 4.0. 2 Go to Settings > Language.... The Languages dialog box is displayed (see Figure 1‐15).


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OVERVIEW Downloading a Dictionary from the Weatherford Website

Figure 1-15: Languages

3 Click Download... to see if Weatherford provides the dictionary on the internet.

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This operation can only be done if you are connected to the Internet.

WellFlo will access the dictionary download site and display a list of available dictionaries (see Figure 1‐16).

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OVERVIEW Adding a New Dictionary Figure 1-16: Download Languages

Adding a New Dictionary If a particular language is not available on either location (application and Website), then you can create a dictionary.

TO ADD A NEW DICTIONARY: 1 Open WellFlo 4.0. 2 Go to Settings > Language.... The Languages dialog box is displayed. 3 Click Add…. The Add Language Wizard is displayed (see Figure 1‐17).


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OVERVIEW Adding a New Dictionary

Figure 1-17: Add Language Wizard

4 Select New dictionary, and click Next. Figure 1-18: Add Language Wizard

5 Enter a unique Language name, and click Next. Once a language name is selected, the next page allows you to edit the dictionary. By default, the dictionary is populated with the currently active dictionary (see Figure 1‐19).

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OVERVIEW Adding a Dictionary from an Existing File Figure 1-19: Dictionary

Adding a Dictionary from an Existing File Use this option if you already have a dictionary file you obtained from Weatherford support or a colleague or used Excel to create one (see accompanying documentation on how to use Excel to create dictionaries).

TO ADD A DICTIONARY FROM AN EXISTING FILE: 1 Open WellFlo 4.0. 2 Go to Settings > Language.... The Languages dialog box is displayed. 3 Click Add…. The Add Language Wizard is displayed (see Figure 1‐20).


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OVERVIEW Adding a Dictionary from an Existing File

Figure 1-20: Add Language Wizard

4 Select Load an existing dictionary, and click Next. Figure 1-21: Add Language Wizard

5 Enter a Language name, and click ... to browse to the file. The Open dialog box is displayed (see Figure 1‐22).

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OVERVIEW Adding a Dictionary from an Existing File Figure 1-22: Open

WellFlo makes sure that you have entered a valid (non empty) name of an existing dictionary file. At this version, the file content is not verified. 6 Select a dictionary, and click Open. The selected file is shown in the Dictionary file: textbox (see Figure 1‐23). Figure 1-23: Add Language Wizard

7 Click Next >>. The language is added to the Installed Languages list (see Figure 1‐24).


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OVERVIEW Creating A WellFlo 4.0 Dictionary

Figure 1-24: Languages

Creating A WellFlo 4.0 Dictionary In order to follow the procedure outlined here, you must use 2003 Professional Edition or a newer version of Excel. If you have WellFlo installed on your machine and have run it at least once you can find the default dictionary file in: %USERPROFILE%\Local Settings\ApplicationData\EPS\WellFlo\language

TO CREATE A DICTIONARY: 1 Open WellFlo 4.0. 2 Go to File > Open.

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The Open dialog box is displayed (see Figure 1‐25). Figure 1-25: Open

The default dictionary file is Dictionary.ENU.xml. 3 If you know the dictionary file location, locate and open the file. 4 Open the file as an XML list (see Figure 1‐26). Figure 1-26: Open XML

5 Select As an XML list, and click OK. An informational message box is displayed (see Figure 1‐27).


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Figure 1-27: Microsoft Office Excel

6 Click OK. Your Excel file should look like Figure 1‐28. Figure 1-28: Microsoft Office Excel File

7 Translate the value column entries to your target language. Do not change anything in the name column. 8 Once done, go to File > Save As… and select the XML Data (*.xml) option from the Save as type drop‐down list. 9 Enter a file name, and click Save.

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OVERVIEW Applying a Different Installed Language

Applying a Different Installed Language The Languages dialog box lists all of the languages in which you can display a dictionary. You can apply a different language once during a session.

TO APPLY A DIFFERENT INSTALLED LANGUAGE 1 From WellFlo’s main window, choose Settings > Language.... The Languages dialog box is displayed (see Figure 1‐29). Figure 1-29: Languages

2 Select the language that you want to use for your dictionary. 3 Click OK.


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OVERVIEW Setting-Up and Running a WellFlo Model

The dictionary is displayed in the selected language.

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Wellflo allows you to change the language only once during a session. If you want to change the language a second time, you must close WellFlo, re-open WellFlo, and then select the language that you want to use.

SETTING-UP AND RUNNING A WELLFLO MODEL WellFlo requires the setting‐up of a Well and Reservoir Description, for which the following data are required: •

Reservoir (or production tests)

•

Well Completions

•

Surface Facilities

•

Fluid Properties

Some choices are also required in terms of:

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•

PVT Model

•

IPR

•

Vertical Lift capabilities

•

Temperature and Choke calculations


OVERVIEW Configuration

Configuration The following categories of data must be entered: •

System data preparation can be performed via the Configuration screens. Depth References also are set‐up here.

•

Users must also select a Reservoir Model for the computation of the IPR. This may consist of up to 36 separate Layers. Data entry can be made using either the simple Test Point model based on production test data; the more complex Layer Parameters model, which uses the theoretical semi‐steady‐state inflow equation and includes the effects of the various skin factors; or the direct entry of the Productivity Indices (PI).

•

Reservoir fluid PVT Data must be entered. There is a choice of: — Black Oil (with Water‐Cut (WCT) and Gas/Oil Ratio (GOR)) — Dry Gas (with Water/Gas Ratio (WGR)) — Gas Condensate (with Water/Gas Ratio (WGR) and Condensate/Gas Ratio (CGR)) — Volatile Oil (with WCT and GOR).

Correlations are used for the first two fluid types, while Gas Condensate and Volatile Oil systems are handled by an Equation of State (EOS). Computed fluid properties can be tuned to measured data, if such data is available. •

ESP or Gas‐Lift data can be entered if appropriate (see “ESP Design” on page 273 or “Gas Lift Design” on page 289).

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These GLV and ESP options are separately licensed withinWellFlo.


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OVERVIEW Analysis

Analysis The Analysis section of WellFlo consists of a series of screens in which users can set‐up options for the type of analysis required. The main options are described as follows: •

Operating Conditions — There is a choice of Pressure Drop calculations (e.g. end to end pressure drop, knowing one end Pressure and a Flow Rate) or Operating Point determination (e.g. flow rate and pressure at a given node, knowing both end pressures).

•

Sensitivities — Users can run a single base case, or up to two Sensitivities (i.e. study the effect on the results of two independent sets of variables ‐ 10 values per set). The choice of variable is limited to those appropriate for the models that have been selected.

Design •

Gas‐Lift can be modeled by letting the program predict Gas Entry Depths (i.e. either from among the specified Valves, or at the Deepest Possible Entry Point), according to Casing and Tubing Pressures, or by ʺforcingʺ Gas Entry at a certain Valve regardless of the Casing and Tubing Pressures.

•

The positioning and sizing of Unloading and Gas‐Lift Valves can be optimized using the Gas‐Lift Design option.

•

The selection of the most suitable Electrical Submersible Pump (ESP), can be optimized using the ESP Design option, as can the setting depth of the ESP, (see “ESP Design” on page 273).

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These GLV and ESP options are separately licensed within WellFlo.

When the model is set‐up for calculation, users can save the set‐up in the same *.WFL file. Results can then be calculated.

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OVERVIEW Output

Output The output section allows users to save a complete record of the calculated Results and Input Data to a file within WellFlo. Users can review an earlier run on screen or make hard copy at any time without having to re‐run the calculations. An option is also provided for the program to write two Log files of the calculations (extension *.LOG). These provide more detail than is normally required for a Report and are very useful if users wish to look more closely at the calculations, either in a text editor or in a spreadsheet. Otherwise the *.LOG option should not be invoked. Information in the and Log Files is designed to be viewed or printed out with the Windows text editors, although many other text editors can be used. The Log (*.LOG) files (if enabled) are written by default to the current well data directory. See “Configuring Preferences” on page 18 for more information on setting up *.LOG files.

USE OF DEPTHS AND DEVIATIONS This section covers the way in which the positions of Well Components are specified within WellFlo, in terms of Measured Depths (MDs.), Total Vertical Depth (TVDs) and Deviation Angles. The data for this is entered in the Reference Depths configuration screen (see “Reference Depths” on page 71). The Wellbore Deviation configuration screen (see “Wellbore Deviation” on page 96) contains the Measured and Vertical Length of the component, the Measured Depth (MD) and True Vertical Depth (TVD) to the node at the bottom of the component, and the average Deviation Angle of the Component.


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OVERVIEW Depth Conventions

Depth Conventions The Depth Conventions in WellFlo are explained with reference to the following three illustrations: •

Schematic of Well Depth Conventions (see Figure 1‐30)

•

Schematic of Well Component Depths (see Figure 1‐31)

•

Schematic of Well Component Deviation (see Figure 1‐32)

The first point is the Depth Reference (Zero Depth). Frequently, users will have deviation or completion data in terms of the drilling depth (e.g. below RKB). However, the Producing Well now has a Wellhead that is physically at a different depth. Referring to Figure 1‐30, the Depth to the bottom of a completion component might be defined as measurement #1, from the Drilling Report. Obviously, the Pressure Drop should only be calculated over measurement #3, since that is the physical Length of Pipe below the Wellhead. The measurement #2, represents the Depth of the Wellhead below the Wellʹs original Depth Reference. In WellFlo, if this the case, users can specify the Elevation of the Depth Reference above Permanent Datum and the Elevation of the Wellhead above Permanent Datum in the Reference Depths configuration screen. From these quantities, the Length for measurement #2 is determined. All Well Components with a Length attribute can now have their Depth specified in terms of measurement #1, the Depth below Well Reference.

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OVERVIEW Depth Conventions Figure 1-30: Schematic of Well Depth Conventions

The illustration in Figure 1‐31 extends this logic to the whole Well system. In the configuration screens for each component, the Length Increment is the Measured Length of the component, while the TVD Increment is the Vertical Length of the component. The Measured Depth and TVD refer to the Depth to the Component Node (i.e. the bottom end) from the Depth Reference (e.g. RKB).


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OVERVIEW Depth Conventions

Figure 1-31: Schematic of Well Component Depths

The Incremental Component attributes are explained in Figure 1‐32.

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OVERVIEW Depth Conventions Figure 1-32: Schematic of Well Component Deviation

When users are entering a well component description and wish to specify depths below well Depth Reference, incremental lengths will be calculated automatically. Alternatively, users can enter the incremental lengths and have WellFlo calculate the Total Depths and Deviation Angle (Segment Deviation from Vertical). The alternative method of data entry is via the configuration screens available for the following Surface and Well Components: •

“Wellbore Deviation”

•

“Surface Terrain Data”

•

“Wellbore Equipment”

•

“Surface Equipment”

•

“Gas Lift Data Configuration”

•

“ESP Data Configuration”


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OVERVIEW System Description and Data Files

SYSTEM DESCRIPTION AND DATA FILES This topic deals with the subject of setting‐up and storing a WellFlo model for analysis, and serves as an introduction to the types of data involved and the files that are used to store data and results. Any WellFlo system under analysis consists of several parts, including: •

General data, including the Depth Reference data on which all other well descriptions will be based

•

Well and Surface components description

•

Fluid Properties (PVT)

•

Reservoir data (Inflow Performance — IPR)

•

Gas‐Lift or ESP data

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These GLV and ESP options are separately licensed within WellFlo.

The whole of the system description as outlined above, together with the analysis control data (e.g. choice of sensitivity variable), is stored in a single file, which is given the extension *.WFL (binary format). Results from an analysis can be stored in output files. There are also two optional computational log files for each run, called WellFlo.Log and Analysis.Log.

WellFlo Data Files WellFlo data for each well is stored in a binary file with extension *.WFL. This file contains all the information needed to make a run of WellFlo. Users could view or edit the ASCII file with a text editor, but for safety, any changes should be made from within WellFlo itself. A modified file can be written over the original file, or saved under a new name.

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SECTION 2 CONFIGURATION

This section describes the process for configuring a well model in WellFlo, including the well and flow type, flow correlations, reference depths, fluid parameters and wellbore and surface equipment. This section also explains the reservoir layer data configuration and temperature modeling. CHAPTER 2 Configuration ................................................................................... 55 CHAPTER 3 Reservoir Layers ............................................................................ 129 CHAPTER 4 Temperature Model ....................................................................... 193

Chapter 2 CONFIGURATION This chapter explains how to configure a well model in WellFlo. Configuration ................................................................................... 56 General Data ..................................................................................... 58 Well and Flow Type ........................................................................ 60 Flow Correlations ............................................................................ 65 Reference Depths ............................................................................. 71 Fluid Parameters .............................................................................. 73 Tuning PVT Models ........................................................................ 86 Wellbore Deviation .......................................................................... 96 Example: Entering New Rows of Data ..................................... 99 Example: Editing Existing Rows of Data ................................ 101 Wellbore Equipment ..................................................................... 102 Adding Tubing ........................................................................... 102 Adding Casing ............................................................................ 104 Adding Restrictions ................................................................... 106 Adding Trace Points .................................................................. 108 Surface Terrain Data ...................................................................... 110 Surface Equipment ........................................................................ 114 References ....................................................................................... 127


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CONFIGURATION Configuration

CONFIGURATION To configure a new well, you must first create a new model. To start a new model, click Create a new model under the Project Tasks menu on the initial Getting Started screen (see Figure 2‐1). Figure 2-1: WellFlo Getting Started

A new Untitled model is opened (see Figure 2‐2).

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CONFIGURATION Configuration

Figure 2-2: New WellFlo Model

The WellFlo Dashboard displays default values set to zero for the new model. Go to File > Save As... to name the WellFlo model and save it as a *.wflx file. You now can follow the Configuration menu to set up the Well Model. A red X indicates screens that have not been configured sufficiently. A green check mark indicates that the screen has been configured. Incomplete configuration screen

Completed configuration screen Incomplete configuration screen, with sufficient data for calculations.


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CONFIGURATION General Data

GENERAL DATA The General Data configuration screen is generated by selecting the General Data option from the Configuration menu; it is used to record important details for the Well Model under analysis.

TO ENTER GENERAL DATA: 1 Open the Configuration menu in the Navigator. 2 Select General Data from the Model Navigator. The General Data configuration screen is opened in the main content pane (see Figure 2‐3). Figure 2-3: General Data

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CONFIGURATION General Data

3 Fill in the following data entry fields: •

Company. The Company name relating to the current well model.

•

Well. The well name of the well to be analyzed.

•

Platform. The platform name associated with the current well model.

•

Objective.Any objectives for the well analysis (e.g. effects of introducing Gas‐Lift).

•

Field. The field name associated with the current well model.

•

Location. The geographical location associated with the current well

model. •

Analyst. The user name/s.

•

Date. The Date/s on which the analysis is being performed.

•

Notes. Additional useful details.

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The standard Windows keyboard commands for Copy (CTRL+C), Cut (CTRL+X) and Paste (CTRL+V) all can be used to edit and transfer text to/from a word processor (or another WellFlo file) via the Clipboard.

4 Click Apply to save your changes.

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After data is entered in a configuration screen, the red X to the right of the screen name is changed to a green checkmark. Screens containing initial default selections show a green check on start-up.

5 Click Forward to advance to the next configuration screen.


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CONFIGURATION Well and Flow Type

WELL AND FLOW TYPE The Well and Flow Type configuration screen is used to select the fluid flow direction and type for the current well. The Well Type can be set to Producer, Injector or Pipeline, and Fluid Flow can occur in the Tubing, Annulus or both.

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Pipeline mode will display only surface components in the system diagram, with a few appropriate modifications to terminology. The Flow Type settings become irrelevant in this case.

With certain Well configurations, some buttons will be disabled: •

Fluid Type is only allowed to be Dry Gas or Water for Injection mode (i.e. Injection radio button is enabled).

•

Artificial Lift Method options are disabled if Injector or Pipeline is selected for the well type.

•

Flow Type and Well Orientation options are disabled if Pipeline is selected for the well type.

TO ENTER WELL AND FLOW TYPE DATA: 1 Open the Configuration menu in the Navigator. 2 Select Well and Flow Type from the Model Navigator. The Well and Flow Type configuration screen is opened in the main content pane (see Figure 2‐4).

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CONFIGURATION Well and Flow Type Figure 2-4: Well and Flow Type

3 Select Producer, Injector or Pipeline for the Well Type.

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The only Fluid Types allowed with this option are single-phase Gas or Water, so Condensate Wells, and Wells with ESPs or Gas-Lift Valves, are not allowed to be set as Injectors.

4 Select None, Continuous gas lift, Intermittent gas lift or ESP for the Artificial Lift Method. 5 Make selections for the following other properties:


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Flow Type •

Tubing. Sets the well as a standard Producer or Injector through the tubing.

•

Annular. Sets the well as a Producer or Injector through the annulus.

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When this option is selected for Gas-Lift, gas is assumed to be injected down the tubing.

This option may also be selected for Pipelines, but there will be no Tubing components for it to apply to. •

Tubular and Annular. Sets the well as flowing through both the Tubing and

the Annulus.

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When this option is selected for Gas-Lift, frictional pressure losses between the Casing Head and the active Gas Lift valve are ignored.

This option may also be selected for Pipelines, but there will be no Tubing components for it to apply to.

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Fluid Type The single selection option is applied to all Layers in the Reservoir (i.e. all oil, or all gas, etc.). The Black Oil, Water and Dry Gas properties are all modeled using Correlations, whereas Condensate and Volatile Oil properties are modeled using a four‐component Equation of State (EoS) derived by EPS1. •

Black Oil (or Water). Selects Oil as the fluid for a Production well, or Water

as the fluid for an Injection well. Use this for produced Gas‐Oil Ratios (GORs) less than 2000 scf/STB (i.e. with or without Water), and optionally for higher produced GORs up to 200,000 scf/STB.

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The Water option is available only when an Injection Well is selected.

•

As Temperatures and Pressures increase, the Black Oil Correlations usually predict an increasing amount of Gas passing into solution, and they never model evaporation of the lighter Oil fractions into Gas. For produced GORs greater than 20,000 scf/STB, and especially in extreme conditions, the Condensate Equation of State is likely to be a more realistic model.

•

Volatile Oil. Selects Volatile Oil as the fluid for a Production well only. The GOR range is from 2000 to 200,000 scf/STB. This uses the same Equation of State as the Condensate option, but allows entry of fluid ratios in Black Oil terms (i.e. GOR and WCT), rather than in Gas terms (i.e. CGR and WGR).

•

Condensate. Selects Gas Condensate as the fluid for a Production well only. Use this for retrograde Condensates and Wet Gases (with or without Water). The range of the Condensate‐Gas Ratio (CGR) is from 5 to 500 STB/MMscf.

•

Dry Gas. Selects Dry Gas as the fluid for a Production well (i.e. Dry Gas production with or without water) or an Injection Well.

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Only the Water and Dry Gas options are available when an Injection Well is selected.


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Well Orientation The single selection option is applied to all Layers in the Reservoir. The Vertical category includes Slant wells. At angles above about 75°, the Horizontal category may be more appropriate. It is actually the Well Orientation relative to the Layer that is significant for IPR calculations. Thus a well inclined at 60° from vertical in a layer dipping at 30° would effectively be Horizontal for inflow purposes. The difference in the calculation of IPR/IIR between a Vertical Well and a Horizontal Well is accounted for in the definition of some of the Skin components.

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The Well Orientation option selected here has no implications beyond the Skin computation and does not impose any constraint on the Well Description (i.e. Casing Angle of Deviation) for Nodal Analysis.

•

Vertical. Selects the Completion as Vertical for Skin computations.

•

Horizontal. Selects the Completion as Horizontal for Skin computations. If the frictional losses in the horizontal section are negligible when compared to the drawdown into the Well, there is no real need to model the horizontal section in great detail. When this is the case it can be modeled with just one fluid entry point, half-way along the horizontal section.

If the flow profile is of interest, or the frictional losses in the horizontal section are significant relative to the drawdown, it is better to define the horizontal section as a series of fluid entry points, so that the frictional losses can be modeled between them. These multiple entry points can be set up manually by defining up to 36 sections. The same result can be achieved automatically by using this button. Each segment will correspond to a section of the drain-hole, with a fluid entry at its mid-point, and a Rectangular Drainage Area.

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The standard Windows keyboard commands for Copy (CTRL+C), Cut (CTRL+X) and Paste (CTRL+V) all can be used to edit and transfer text to/from a word processor (or another WellFlo file) via the Clipboard.

6 Click Apply to save your changes. 7 Click Forward to advance to the next configuration screen.

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CONFIGURATION Flow Correlations

FLOW CORRELATIONS The Flow Correlations configuration screen is used to select the Nodal Analysis Correlations to use in the Nodal Analysis calculations. Five categories of correlation can be selected: •

Well and Riser Flow Correlation

•

Deep Well Flow Correlation

•

Pipeline Flow Correlation

•

Downcomer Flow Correlation

•

Choke Correlation

The Well/Riser, Pipeline and Downcomer Flow Correlations are functionally the same. The Well/Riser and Deep Well categories are used in Well Components below the Wellhead/Xmas Tree (i.e. Tubing and Casing Components), and cover Vertical, Slant and Horizontal Wells. The Riser, although a Surface Component, is assigned the same Flow Correlation as the upper part of the Well. The Downcomer component is intended to model a section of Flow Line in which the flow is downwards, and where the Flow Correlation and Calibration L‐Factor assigned to Flow Line components are not considered suitable (e.g. steep or vertical downflow). The Downcomer can be assigned its own Flow Correlation and Calibration L‐Factor. Since the pressure gradient is largely hydrostatic, the application of an L‐factor to the total pressure gradient is equivalent in principle to the Palmer Correction2.


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The L‐Factors can be used to calibrate or adjust the Pressure Drop computations in the Well, Pipeline and Sub‐Critical Choke sections. During Nodal Analysis, the total Pressure Gradient in each computation increment (i.e. nominally 250 ft), will be multiplied by the value specified for the appropriate L‐Factor (i.e. for an L < 1, the computed Pressure Drops will be reduced, and for an L > 1 they will be increased).

i

L is applied within each computation increment. This is not quite the same as scaling the overall Pressure Drop after it has been computed.

TO ENTER FLOW CORRELATIONS: 1 Open the Configuration menu in the Navigator. 2 Select Flow Correlations from the Model Navigator. The Flow Correlations configuration screen is opened in the main content pane (see Figure 2‐5).

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Figure 2-5: Flow Correlations

3 Make selections for the following Flow Correlations, Velocity Multipliers and L‐Factors: •

Well and Riser Flow Correlation. Select the Vertical Flow Correlation to use

for Well Nodes and Risers from the drop‐down menu. •

Change Correlation at MD. To apply different Flow Correlations in the

upper and lower parts of the Well Model, check the Change Correlation at MD checkbox, and in the adjacent field, enter the Measured Depth (MD) at which the Correlation change will be applied (e.g. following this entry, a Deep Well Flow Correlation could be applied below the specified Measured Depth (MD). This could be used to model the horizontal section of a Well with a different Correlation from the Vertical/Slant section).

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The Change Depths should correspond to Node Depths. If users enter a Depth that lies within a Component, WellFlo will use the top or bottom of the Component, depending on which is nearer.


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•

Deep Well Flow Correlation. Select the Vertical Flow Correlation to use (i.e. instead of the Well and Riser Flow Correlation), below the specified Measured Depth (MD) in the overlying field.

•

Well and Riser L-Factor. Enter a multiplier to apply to all Pressure Drops computed in the Well and Riser Components. This value can be used as a Sensitivity for fine‐tuning a Correlation to match measured data. There is a facility in the Sensitivities screen (see “Running Sensitivities” on page 220) to automatically find the value that exactly matches a single measured data point, or that best matches a set of measured data points.

•

Critical flow for liquid loading. Enter a multiplier for the Critical Gas

Velocity required to unload Water. This Velocity is computed from the formula published by Turner3 and modified by Coleman et al4 and will be multiplied by the user‐defined factor before being Logged or Plotted: Figure 2-6: Critical flow for liquid loading

(Oilfield Units) Refer to “Critical Unloading Rate” on page 233 for more details.

i i •

In the EPS Mechanistic Flow Correlation, the Annular Flow and Mist Flow Regimes are not allowed below this multiplied Gas Velocity.

This formula is by default evaluated with the Water properties, even when there is no Water (i.e. WGR=0), to give a continuous and conservative result. However, to use the Oil Properties instead when there is no Water, enter "0" for the Registry Value turner-water-lift.

Downcomer Flow Correlation. These are essentially Risers with downflow

and can be assigned a component‐specific Flow Correlation and Calibration Factor, because the characteristics of downflow are radically different.

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Select the Vertical Flow Correlation to use for Downcomer Nodes from the drop‐down menu. The Downcomer option allows the Well and Surface Tubing to be partitioned into a total of three groups, each with a different Flow Correlation and/or L‐Factor. The WellFlo nomenclature suggests that the Component angle from the vertical will be around 0 for Risers, around 90 for Flow Lines, and around 180 for Downcomers, but the chosen Component group dictates no more than the initial default angle for a new Component. •

Downcomer L-Factor. Enter a multiplier to apply to all Pressure Drops computed in the Downcomer Components (the effect on Pressure Drops is described in the General section above).

•

Pipeline Flow Correlation. This is used for Surface Components beyond

the Wellhead/Xmas Tree (e.g. Flow Lines, but not Risers or Downcomers). Select the Horizontal Flow Correlation to use for Flow Line and Bend Nodes from the drop‐down menu. •

Pipeline L-Factor. Enter a multiplier to apply to all Pressure Drops computed in the Flow Line and Bend Components (the effect on Pressure Drops is described in the section above).

•

Sub-Critical Choke L-Factor. Enter a multiplier to apply to all Sub‐Critical Pressure Drops computed in the Choke, Restriction or SSSV Components. The Sub‐Critical Choke L‐Factor simply re‐scales the Pressure Drop computed across the Choke in Sub‐Critical Flow.

•

Choke Correlation. Select the Choke Correlation to use from the drop‐down menu. The Choke Correlation is for Critical Flow with Black Oil Systems or low GLR (< 10,000 scf/STB) Gas/Condensate/Volatile Oil systems. It will only be applied for a particular Component if the Use Critical Flow Equation checkbox option is checked; if this checkbox option is unchecked, the Sub‐Critical Flow equation will be used for these Components.

If the system has a high GLR (>10,000 scf/STB), a single, continuous equation is used to model both Critical Flow and Sub‐Critical Flow.


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If the Customized option is selected in the drop‐down menu, this enables the three underlying data entry fields.

i •

Refer to “Pressure Drop Through a Restriction” on page 240 for more details of how these Correlations are applied.

Coefficients for Customized Choke Correlation Option. If these data entry

fields are enabled by selecting the Customized choke correlation option in the overlying selection field, users can specify their own Coefficients by entering values for A, B and C, to be used in an equation of the form: Pup = (B x QlD x GLRC) / (DchokeA) Where Pup = Critical Upstream Pressure These Coefficients can be selected as Sensitivity Variables to assist with identifying the best values (i.e., B is directly equivalent to the L‐Factor).

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The Coefficients offered as a default are those of Baxendell, the median of the five pre-defined Correlations (refer to the table of choke correlations: “Surface Chokes” on page 240 in “Pressure Drop Through a Restriction” on page 240 for more details).


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CONFIGURATION Reference Depths

REFERENCE DEPTHS The Reference Depths configuration screen contains the information necessary to link the downhole and surface components to a common depth reference. Referring to Figure 2‐7, the depth to the bottom of a completion component might be defined as measurement #1, from the drilling report. Obviously, the pressure drop should only be calculated over measurement #3, since that is the physical length of pipe below the wellhead. The depth measurement #2 represents the depth of the wellhead below the wellʹs original Depth Reference (Zero Depth). Figure 2-7: Reference Depths

In WellFlo, if this is the case, users can specify the elevation of the depth reference above Permanent Datum and the elevation of the wellhead above Permanent Datum. From these quantities, the measurement #2 is determined. All well components with a length attribute can now have their depth specified in terms of #1, the depth below well reference.


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CONFIGURATION Reference Depths

TO SET REFERENCE DEPTHS: 1 Open the Configuration menu in the Navigator. 2 Select Reference Depths from the Model Navigator. The Reference Depths configuration screen is opened in the main content pane (see Figure 2‐8). Figure 2-8: Reference Depths

3 Select the Well Type. 4 Enter values for the distances in the Distance from section. The fields in this screen depend on the well type (Onshore, Subsea or Platform) selected. 5 Select a reference point (Wellhead, Kelly Bushing/Rotary Table or Other) from which all vertical depths are taken in the Zero Depth section. 6 Click Apply to save your changes. 7 Click Forward to advance to the next configuration screen.

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CONFIGURATION Fluid Parameters

FLUID PARAMETERS The Fluid Parameters configuration screen is used to select the Fluid Type and enter fluid data. There are facilities for checking and calibrating computed Fluid Properties against measured data. Most of the PVT Fluid Parameters can be Tuned individually. The Tuning Coefficients are stored as part of the WellFlo data file and will be applied in any subsequent calculation made here or in any other part of the program. These properties must be set when the Black Oil option is selected in the Fluid Type section and are used to set‐up and calculate the various Black Oil Fluid Parameter values.

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The Black Oil category in WellFlo accepts a producing GOR as high as 200,000 scf/STB. None of the Black Oil correlations have been validated much above 2,000 - 2,500 scf/STB, and for more accurate modeling of Oil Properties with GORs greater than 2000 scf/STB, it may be more appropriate to use the Volatile Oil option.

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A Gas Condensate system can be classified as a Gas Reservoir with a typical solution Gas/Oil Ratio (GOR) between 5,000-69,000 scf/STB and/or Condensate Liquid/Gas Ratio (CGR) between 14.5-200 STB/MMscf (although Gas Condensate systems can still exist outside these ranges). The Stock Tank Condensate API Gravity can vary between less than 30° to greater than 80°, but is generally between 40-65°.

A Volatile Oil system can be classified as a Reservoir with a typical solution Gas/Oil Ratio (GOR) in the range of 1,500‐3,500 scf/STB, API Oil Gravity greater than 40‐45° and an Oil Formation Volume Factor (Bo), greater than 2.0 rb/stb.


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Figure 2-9: Fluid Parameters

(Bradley H.B. (Editor); (1987). "Petroleum Engineering Handbook", Society of Petroleum Engineers, Richardson, TX., USA).

A high GOR limit has been allowed to provide a means of including a Gas Layer (or Layers) commingling with the Oil Layer (or Layers). The Gas Layer can be represented as a very high GOR Oil Layer.

TO ENTER FLUID PARAMETERS: 1 Open the Configuration menu in the Navigator. 2 Select Fluid Parameters from the Model Navigator. The Fluid Parameters configuration screen is opened in the main content pane (see Figure 2‐10).

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Figure 2-10: Fluid Parameters

3 Enter values for the following fluid parameters:

Fluid Type: The single selection option is applied to all Layers in the Reservoir (i.e. all oil, or all gas, etc.). The Black Oil, Water and Dry Gas properties are all modeled using Correlations, whereas Condensate and Volatile Oil properties are modeled using a four‐component Equation of State (EoS) derived by EPS1. •

Black Oil (or Water). Selects Oil as the fluid for a Production well, or

Water as the fluid for an Injection well. Use this for produced Gas‐Oil Ratios (GORs) less than 2000 scf/STB (i.e. with or without Water), and optionally for higher produced GORs up to 200,000 scf/STB.

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The Water option is only available when Injector is selected in the Well and Flow Type configuration screen.


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As Temperatures and Pressures increase, the Black Oil Correlations usually predict an increasing amount of Gas passing into solution, and they never model evaporation of the lighter Oil fractions into Gas. For produced GORs greater than 20,000 scf/STB, and especially in extreme conditions, the Condensate Equation of State is likely to be a more realistic model. •

Dry Gas. Selects Dry Gas as the fluid for a Production well (i.e. Dry Gas

production with or without water) or an Injection Well.

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Only the Water and Gas options are available when Injector is selected in the Well and Flow Type configuration screen.

•

Condensate. Selects Gas Condensate as the fluid for a Production well only. Use this for retrograde Condensates and Wet Gases (with or without Water). The range of the Condensate‐Gas Ratio (CGR) is from 5 to 500 STB/MMscf.

•

Volatile Oil. Selects Volatile Oil as the fluid for a Production well only. The GOR range is from 2000 to 200,000 scf/STB. This uses the same Equation of State as the Condensate option, but allows entry of fluid ratios in Black Oil terms (i.e. GOR and WCT), rather than in Gas terms (i.e. CGR and WGR).



Processed Fluid Data: The five fields in this section are used to enter basic production data. Oil Specific Gravity and Oil API Gravity and Water Salinity (NaCl Equivalent) and Water Specific Gravity are linked pairs of fields (i.e. changing one automatically updates the other of the pair, so that data remain consistent). •

Oil API Gravity. Enter the Oil API Gravity (or enter the Oil Specific Gravity

in the underlying field). If a new value is entered here, this will automatically update the Oil Specific Gravity field. •

Water Salinity. Enter the Water Salinity (NaCl Equivalent) here (or enter

the Water Specific Gravity in the underlying field). If a new value is entered here, this will automatically update the Water Specific Gravity field. •

Oil Specific Gravity. Enter the Oil Specific Gravity (or enter the Oil API

Gravity in the overlying field). If a new value is entered here, this will automatically update the Oil API Gravity field. Specific Gravities of oil generally lie between 0.73 to slightly above 1.0 and in API Gravity terms, the usual range starts with Water Density at 10° and rises to Volatile Oils and Condensate liquids at around 60-70°.

•

Gas Specific Gravity. Enter the Gas Specific Gravity (i.e. at standard

conditions). For the Vazquez-Beggs correlation, the first-stage separator is assumed to be at 100 psig. Typical values for hydrocarbon gas mixtures range from 0.65 (Dry Gas) to 0.95 (Wet Gas).

•

Water Gravity. Enter the Water Specific Gravity here (or enter the Water

Salinity (NaCl Equivalent) in the overlying field). If a new value is entered here, this will automatically update the Water Salinity field. The salinity of pore waters in reservoirs typically increases by 6 to 160 g/L (6,000 to 160,000 ppm) per km depth. The causes of increased salinity are: — Salt dissolution (primary).


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— Membrane filtration (secondary). Seawater salinity is about 35 g/L (35,000 ppm). Much higher salinities are found in oil field brines. Typical salinities for oil and gas reservoirs are 30 g/L (30,000 ppm) for sandstones and 90 g/L (90,000 ppm) for carbonates. Concentrations of total dissolved solids (TDS) range from 80 to 300 g/L (80,000 to 300,000 ppm) in reservoirs deeper than 1 km.

The following fields are used to select Black Oil Correlations: 4 For Bubble‐Point Pressure (Pb), Solution GOR (Rs) and Oil Formation Volume Factor (Bo), select one of the following options from the drop‐down menu: — Glasø5 — Lasater6 — Standing7 — Vazquez8 — Petrosky9 — Macary10 5 For Oil Viscosity (µo), select one of the following options from the drop‐down menu: — Beal11,12 — Beggs13 — ASTM ‐ Chew — ASTM ‐ Beggs The ASTM method is a two‐point calibration of Dead Oil Viscosity at different Temperatures. The ASTM correlation defines that the variation with Temperature of the Dead Oil Viscosity (μ) is of the form μ(T1)/μ(T2) = (T2/T1)^k, where T1 and T2 are measured in F and k depends on observed data. After selection of this correlation, therefore, the Match option should be used to enter two or more observed Dead Oil Viscosities at different temperatures, followed by a Best Fit.

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When the ASTM correlation is selected, it must be combined with either the Chew and Connally or Beggs and Robinson formula, to correct it for Live Oil. After fitting the observed Dead Oil Viscosities as described above, any observed Live Oil Viscosities should then be compared with the calculated values using the Check option, to guide the choice of Live Oil correction. The ASTM formula does not actually give the Dead Oil Viscosity as a function of its Gravity and Temperature. As this is incompatible with the other Oil Viscosity correlations in WellFlo, constants have been added to the implementation to let it be used without observed data, although this is not recommended. To model a heavy Oil with a low Viscosity the ASTM methods will provide a more accurate resolution to Match. The ASTM part of the correlation is resolved at Atmospheric Pressure (14.6psi), allowing the additional (+) part of the selected ASTM correlation to correct for the liberated Gas. Thus users may enter a range of Temperatures to calculate their Match. 6 For Gas Viscosity (µg), select one of the following options from the drop‐down menu: — Carr14 — Lee15 7 For the Surface Tension of water (Sw), there is a choice of two options: — Basic: This option uses a simplistic correlation with no dependence on Pressure and Salinity. It also invokes a linear Interfacial Tension mixing rule for the multi‐phase flow calculations. — Advanced: This option uses a correlation incorporating Pressure16 and Salinity17 effects on Water Surface Tension; it also invokes a fourth‐root mixing rule for multi‐phase flow calculations involving Oil Surface Tension (after Baker and Swerdloff18).

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Interfacial Tension is important in determining Flow Regimes. The Water Surface Tension is calculated and combined in one of these two selected ways with the Oil Surface Tension (which cannot be Tuned).


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8 To tune any of the correlations against measured data using a minimization routine, click Tune correlations to PVT data .... Tuning the PVT model is very important, since the influence of Fluid Properties, particularly Gas/Oil Ratio (GOR), on pressure drop can be dramatic.

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Data from PVT reports should correspond to Constant Mass/Constant Composition experiments (i.e. CME/CCE), not Constant Volume Depletion experiments (i.e. CVD).

Inorganics: This section is used to enter the Inorganic Impurity Contents of a Dry Gas. 9 Enter Mole Fractions of the main Inorganic Components found in Dry Gas:

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We recommended that you select the Carr et al Correlation if Inorganics are present.

•

H2S. Enter the fractional value (e.g. 0.25)

•

CO2. Enter the fractional value (e.g. 0.25)

•

N2. N2 ‐ Enter the fractional value (e.g. 0.25)

These values will then be available for subsequent calculations. The Wichert‐Aziz19 correction is applied to the z‐Factor. The Carr et al Correlation for Gas Viscosity includes a correction for Inorganics. The Lee et al Correlation does not.

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For the Wichert-Aziz correction to be valid, neither H2S nor CO2 nor their sum may exceed 80% (i.e. 0.80 fraction), and the sum of all three Inorganics may not exceed 99% (i.e. 0.99 fraction). Changes to the Inorganic Fractions may be found to invalidate the Total Gas Gravity already entered in the Gas/Water Fluid Parameters screen.



Emulsion Viscosity: This section is used to enable or disable Emulsion Viscosity Correction during Nodal Analysis and to select a location where Emulsion Viscosity Correction will be applied. Users can enter a table of Viscosity Multipliers as a function of Water‐Cut which will operate on the “raw” Oil/Water Mixture Viscosities (i.e. normally computed by the PVT section). During Nodal Analysis, the Viscosity used for Emulsion will be a multiple of the ʺrawʺ Oil/Water Mixture Viscosity, that is appropriate for the prevailing Water‐Cut. 10 Check the Use emulsion viscosity checkbox. 11 Click Emulsion Viscosity… . The Emulsion Viscosity dialog box is displayed (see Figure 2‐11).


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Figure 2-11: Emulsion Viscosity

12 Select an option from the Use Emulsion Viscosity area to apply Emulsion Viscosity Corrections to specified Well Components: •

None. Emulsion Viscosity Corrections will not be applied in Well Components.

•

In all tubulars. Users can specify a separate set of Viscosity Multipliers for

Tubular Flow and for the Flow Through the Pump, as appropriate. •

Above ESP or GLV. Select this option to apply the Emulsion Viscosity

Corrections from just above the ESP or GLV (if present) to the Outlet Node. The uncorrected Oil and Water Viscosities will be used below the ESP or GLV (if present). When Above ESP or GLV is unchecked, Emulsion Viscosity Corrections will not be applied to an ESP. When checked, Emulsion Viscosity Corrections will be applied to model emulsion effects in the ESP (if one is present).

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13 Select an option from the Available data area to define whether data is based on a table of measured viscosities as a function of water cut or based on a viscosity multiplier. •

Emulsion Viscosity. The emulsion viscosity radio button allows you to define a table of viscosities as a function of water cut.

•

Multiplier. Multiplier radio button allows the you to define a table of viscosity multipliers as a function of water cut.

14 To define how the fluid properties will be treated during the stage‐by‐stage calculations which are carried out for the pump in an Electric Submersible Pumping application, click the Inside ESP tab.

Check: On the Fluid Parameters configuration screen, the Check section is used to examine the results of the selected correlations.

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The calculations made in this section are not carried through to any other part of the program and are purely for reference only. All Fluid Properties for Nodal Analysis are calculated at prevailing conditions wherever necessary, based on the data contained in the Fluid Parameters configuration screen.

15 Enter the check Pressure, Temperature, produced GOR (Gas/Oil Ratio (Rsp)) and produced CGR (Condensate/Gas Ratio (Condensate only)), and click Calculate.

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Volatile Oil calculations will be performed for: 1500 = GOR = 200,000 scf/STB.


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The parameters are calculated in the Properties Out section. •

Condensate => Dew‐Point Pressure (Pdew) and Relative Volume: The Relative Volume (Rel Vol) is defined as the total volume (i.e. at the check Pressure), divided by the volume at the Dew‐Point. It, therefore, equals 1.0 at Pressure = Dew‐Point.

•

Volatile Oil => Bubble‐Point Pressure (Pb) and Relative Volume: The Relative Volume (Rel Vol) is defined as the total volume (i.e. at the check Pressure), divided by the volume at the Bubble‐Point. It, therefore, equals 1.0 at Pressure = Bubble‐Point.

•

Volumetric Fractions, Formation Volume Factor, Viscosity and Density for Oil, Gas and Water: The Vo and Vg terms are the Volumetric Fractions of the Oil and Gas phases at the check Pressure. Vo = 0.0 at the Dew‐Point.

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The Retrograde Liquid Dropout (not displayed in this screen) is simply Vo x Relative Volume. At pressures above Dew-Point, the Viscosity and Density displayed for Oil are set equal to those of Gas for convenience.

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With the exception of Vazquez-Beggs, these correlations assume a single-stage flash to standard conditions. The published Vazquez-Beggs correlation assumes the first-stage separator pressure to be 100 psig and provides for a Pressure (and Temperature) correction to Gas Gravity if different. To simplify the data input, WellFloassumes 100 psig and applies no correction.

If users are comparing with Multi‐Stage Flash experimental data, ensure that the GORs are totaled up from all stages, and enter a Gas Gravity that is the GOR‐Weighted Sum of the gravities from each stage. This screen is not suited to comparison with Differential Liberation data.

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The Bubble-Point Pressure is calculated at the check Temperature for the specified Produced GOR. To check against laboratory PVT data, the measured GOR of the reservoir oil would normally be entered here. Calculations will be performed for 0 = GOR = 200,000 scf/STB, although these correlations were rarely validated above 2000-2500 scf/STB20.



The Solution GOR is calculated at the check Pressure and check Temperature. If the check Pressure is below the calculated Bubble‐Point Pressure, the Solution GOR will be less than the specified Produced GOR. Entering a high producing GOR (e.g. because of excess gas production from another Layer) will not affect the computation of Oil Properties in the Oil Layer. The Bubble‐Point Pressure calculated in this situation is the Bubble‐Point Pressure of the total system (i.e. Associated plus Excess Gas), and it will probably be well above the expected Bubble‐Point Pressure for the Reservoir. However, you can verify that at check Pressures below the Bubble‐Point Pressure, the calculated Oil Properties will be the same, regardless of the value entered for produced GOR. This is because, below the Bubble‐Point Pressure, the specified check Pressure is effectively a Saturation Pressure — the Oil cannot contain any more Gas at that Pressure, no matter how much is available.

Dew-Point/Bubble-Point Systems For a Condensate system, depending on the Gas and Oil Gravities that are specified, increasing the CGR will tend to take the fluid type from Gas Condensate towards Volatile Oil. Eventually, the Saturation Pressure will change from a Dew‐Point to a Bubble‐Point as it passes through the critical Pressure. Since this Fluid Model is primarily designed for modeling Gas Condensate systems, a warning message will be generated if a Bubble‐Point system is detected. You can still continue to work with the specified Condensate system. Alternatively, switch the Fluid Type to Volatile Oil; the results will be the same. Similarly, for a Volatile Oil system, depending on the Gas and Oil Gravities that are specified, increasing the GOR will tend to take the fluid type from Volatile Oil towards Gas Condensate. Eventually, the Saturation Pressure will change from a Bubble‐Point to a Dew‐Point as it passes through the critical Pressure. Since this Fluid Model is primarily designed for modeling Volatile Oil systems, a warning message also will be generated if a Dew‐Point system is detected. Again, you can still continue to work with the specified Volatile Oil system. Alternatively, switch the Fluid Type to Condensate; the results will be the same. 16 Open the Charts tab to select and plot a chart. 17 Click Apply to save your changes.


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CONFIGURATION Tuning PVT Models

TUNING PVT MODELS Tuning the PVT model is very important, since the influence of fluid properties, particularly gas / oil ratio (GOR), on pressure drop can be dramatic. The following example shows how to tune Black oil PVT measured data.

TO TUNE A PVT MODEL: 1 Click the Tune Correlations to PVT Data… button (see Figure 2‐12).

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WellFlo version 4.0 and higher uses a different PVT tuning model than prior releases of the software. If you are using a model that was created with a prior version of WellFlo, you will need to upgrade the well model in order to use the PVT Tuning feature. To do this, click the button Upgrade PVT Model for Tuning (see Figure 2-13).


CONFIGURATION Tuning PVT Models Figure 2-12: Tuning Correlations to PVT Data


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Figure 2-13: Converting WellFlo 3.x Model for Tuning

2 The PVT Tuning Workbench will then appear. (see Figure 2‐14) This workbench interface is divided into two parts: (1) a navigation tree at left and (2) panels at right which correspond to the active tree node. When the workbench is first opened, the Fluid Source Group node (fsgnode) is active and summary data describing the active correlations are displayed in the corresponding panel to the right.

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CONFIGURATION Tuning PVT Models Figure 2-14: PVT Tuning Workbench

For Black oil fluid type, currently the PVT correlations selected are: •

Carr for Gas Viscosity

•

Beal for Oil Viscosity

•

Glasø for Bubble point and Solution GOR

3 When the PVT Tuning Workbench is first opened one fluid model will automatically be generated for the user to edit and tune to experimental data. By default, this model is called, Fluid Model 1. 4 Assign PVT data parameters and Inorganic components as required. 5 Click the Fluid Model 1 node and validate the PVT data. Values for Fluid Type, Gas Gravity and Oil Gravity will automatically be populated based on the data entered in the Fluid Parameters panel. However, GOR (scf/STB) will need to be verified based on experimental conditions. (see Figure 2‐15).


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Figure 2-15: PVT Data for Fluid Model 1

6 Right‐click Fluid Model 1 and select Add Black Oil Experimental Data to add data at a given set of conditions (see Figure 2‐16).

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Additional experiments can be entered for tuning by right-clicking the Fluid Model 1 node and clicking Add Experimental Data. However, only the highlighted data set will be used to tune the correlations

7 Select Black Oil Data in the left panel to and update the laboratory data with values for Saturation Pressure and Temperature corresponding to experimental conditions. 8 Populate the table with data for Pressure, Oil Formation Volume Factor (bbl/STB), Solution GOR (scf/STB), Gas Compressibility Factor, Oil Viscosity (cp) and Gas Viscosity (cp). (see Figure 2‐16). Data can be entered manually

by editing the table and clicking the Insert Row button to create additional rows. Alternatively, data can be imported from a spreadsheet by highlighting the upper left cell and copying and pasting data from the clipboard.

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CONFIGURATION Tuning PVT Models Figure 2-16: Laboratory Data for Tuning

9 Click Match to tune these correlations to the experimental data. The results of the tuning are saved under Tuning Output 1 in the central Tuning menu (see Figure 2‐17). The results screen shows the correlations that have been tuned as well as the RMS error between the experimental data and the tuned and un‐tuned correlations. In addition, the table at right shows the tuning factors used to adjust bubble point pressure, oil formation volume factor, oil viscosity, gas compressibility factor and gas viscosity.

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In general, the closer the tuning factors are to 1.0, the less tuning is required to match the correlation to measured data. So, it is advisable to select correlations which yield tuning factors that are as close as possible to 1.0.


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Figure 2-17: P-V-T Parameters - Tuning Results

10 Select the blackoildata 1 node from the result set to view the results of the tuning. In the panel at right are the laboratory data used for tuning along with the tuned and un‐tuned values for saturation pressure (see Figure 2‐18).

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CONFIGURATION Tuning PVT Models Figure 2-18: Tuning Results

11 Open the Plot tab to view a plot of the current experiment. The experimental data chart is displayed (see Figure 2‐19).


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Figure 2-19: P-V-T Parameters - Experimental Data Chart

The plot provides the option to see the Tuned and Untuned data in a graphical format. Check Experimental Data, Untuned Data or Tuned Data to add those selections to the graph. 12 Open the Graph Data tab to view the Tuned and Untuned data for all the PVT parameters used in Tuning operation in a tabular format (see Figure 2‐20).

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CONFIGURATION Tuning PVT Models Figure 2-20: P-V-T Parameters Plot - Graph Data

13 Click Accept to save the data set. Once the PVT correlations are tuned, an asterisk (*) is assigned to the correlations as shown in Figure 2‐21.


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CONFIGURATION Wellbore Deviation

Figure 2-21: Tuned Correlations

14 Click Forward to advance to the next configuration screen.

WELLBORE DEVIATION The Wellbore Deviation configuration screen is used to view, enter and edit well deviation data. The main deviation data three‐column table allows users to enter data from a deviation survey or import it in from a spreadsheet or other external source (see “Importing Data from an External Source” on page 25). The data must be entered in ascending order of Measured Depths (MDs). The Segment Deviation from Vertical angle is the component deviation angle as illustrated in Figure 2‐22, not the average angle from the Wellhead/Xmas Tree to this point.

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CONFIGURATION Wellbore Deviation Figure 2-22: Schematic of Well Component Deviation

TO ENTER WELLBORE DEVIATION DATA: 1 Open the Configuration menu in the Navigator. 2 Select Deviation under Wellbore in the Model Navigator. The Wellbore Deviation configuration screen is opened in the main content pane (see Figure 2‐23).


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CONFIGURATION Wellbore Deviation

Figure 2-23: Wellbore Deviation

3 Select the deviation data types to Enter Data For from the following options to activate the corresponding parts of the table: •

MD, TVD. Enter each Measured Depth in the system, in ascending order. The corresponding TVD field is updated automatically.

•

MD, Angle. Enter each Angle corresponding to the MD entered. The corresponding TVD field is updated automatically.

•

TVD, Angle. Enter each True Vertical Depth corresponding to the MD

entered. The corresponding Angle field is updated automatically. 4 To import well deviation data, click the Import data from an external source button to open the Data Import Wizard. Import data from external source: Opens the Data Import Wizard, which allows you to configure the data import process.

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CONFIGURATION Example: Entering New Rows of Data

For more information on importing data, see “Importing Data from an External Source” on page 25. 5 To enter data manually, click the Add a new row button to insert a blank row into the table. To navigate through the table, the cursor can be moved with the keyboard arrow, TAB, PAGE UP, PAGE DOWN, HOME and END keys, or the mouse can be clicked on the desired field, using the scroll bar when necessary.

6 Enter deviation data into the new row. When you have finished editing a field, select the TAB key to confirm the edit and move to the next field for editing, or click directly onto the next field. (Select the ESQ. key to abort an edit, if necessary.) WellFlo will translate this tabular well deviation data into an equivalent string of nodes in the Wellbore Deviation chart. 7 Click Apply to save your changes. 8 Click Forward to advance to the next configuration screen.

Example: Entering New Rows of Data Users will normally be entering Measured Depths and True Vertical Depths, or Depths and Angles, from a Deviation Survey. The following example applies to entering a new row of data. If users are editing an existing row in a table, please refer to the section after this one.

TO ENTER MD AND TVD: 1 Click in the first Measured Depth field and enter the measured depth. 2 TAB or click in the True Vertical Depth field. A TVD is immediately calculated assuming a default Angle of zero degrees (or the current angle if there is one). 3 Ignore this value and enter the correct true vertical depth. 4 TAB or click into the Segment Deviation from Vertical field.


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CONFIGURATION Example: Entering New Rows of Data

The correct angle is calculated from the MD (increment) and TVD (increment): Cosine (Angle) = TVD (increment) ÷ MD (increment) 5 Insert additional rows and enter the MD, and so on.

TO ENTER MD AND DEVIATION ANGLE: 1 Click in the first Measured Depth field and enter the measured depth. 2 TAB or click into the Segment Deviation from Vertical field. As the True Vertical Depth field is traversed, a TVD is immediately calculated assuming a default Angle of zero degrees. Ignore this value for the moment. 3 In the Segment Deviation from Vertical field, enter the Deviation Angle. 4 TAB or click into the next MD field. The TVD in the row that was just edited will be correctly updated from the MD and angle, using: TVD (increment) = MD (increment) × Cosine (Angle) 5 Insert additional rows and enter the MD, and so on.

TO ENTER TVD AND DEVIATION ANGLE: 1 Click in the first True Vertical Depth field and enter the TVD. 2 TAB or click into the Angle field. An angle is immediately calculated assuming a default MD of 5000 ft (or the current MD if there is one). Ignore this value for the moment. 3 In the field, enter the correct deviation angle. 4 TAB or click into the next TVD field. The MD in the row that was just edited will be correctly updated from the TVD and Angle, using: MD (increment) = TVD (Increment) / Cosine (Angle)

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CONFIGURATION Example: Editing Existing Rows of Data 5 Insert additional rows and enter the TVD, and so on. If Angle is entered first, the TVD is calculated from the MD (increment) x Cosine (Angle). A default MD (increment) of 5000 ft is used, so the TVD will initially be meaningless. Enter the MD and the TVD will be updated when you TAB or click out of the MD field. It is normally advisable not to start with the Segment Deviation from Vertical field.

Example: Editing Existing Rows of Data When the table has been set‐up, one of the rows may need to be edited. The following example explains how this can be done. Suppose users want to correct an Angle entry, keep the same MD, and get WellFlo to update the TVD.

TO EDIT THE TABLE: 1 Double‐click in the Measured Depth field. 2 TAB to (or double‐click on) the Segment Deviation from Vertical field, change the value. 3 TAB (or click) out of the field. The TVD will be updated.

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WellFlo always remembers the last two fields that were edited (or put into edit mode — Measured Depth and Segment Deviation from Vertical in this case), and recalculates the third one. If you had double-clicked the True Vertical Depth field instead, then edited the Angle, the MD would have been updated, and so on.


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CONFIGURATION Wellbore Equipment

WELLBORE EQUIPMENT The Wellbore Equipment configuration screen is used to view, enter and edit Well Equipment Data.

Adding Tubing This option is used to add a length of Tubing to the well. The Segment Length increment is the measured length of the component. The Measured Depth refers to the total depth down to the node (i.e. at the bottom of the component or at the deepest fluid entry point (bottom‐most component — nominally the middle of the perforations)).

TO ADD TUBING: 1 Open the Configuration menu in the Navigator. 2 Select Equipment under Wellbore in the Model Navigator. The Wellbore Equipment configuration screen is opened in the main content pane (see Figure 2‐24).

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CONFIGURATION Adding Tubing

Figure 2-24: Wellbore Equipment

3 Open the Tubing tab, if necessary. 4 Select the data type, Length or Depth, from the Enter Data For section. 5 Insert new rows into the table, as necessary.

Tubing data can be entered manually or inserted from the WellFlo catalog.


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CONFIGURATION Adding Casing

6 Add data from the WellFlo Tubing catalog by clicking the Select row data from catalog button or enter table data: •

Name. A name to describe the tubing segment.

•

Start Point Measured Depth. The length from the wellhead (or the end of the previous tubing segment) to the downstream end of this tubing segment. The Segment Length field is recalculated as follows: Total Length from Wellhead minus the total length to the end of the previous tubing segment.

•

End Point Measured Depth. The True Vertical Depth increment of the

downstream end of the tubing segment relative to the upstream end of the tubing segment. The Segment Length field is recalculated if the new True Vertical Depth increment is greater than the current Segment Length. In this case, the Segment Length is set equal to the True Vertical Depth increment. •

Segment Length. The length of the tubing segment.

•

Internal Diameter. The internal diameter of the tubing (used in conjunction

with Roughness in the pressure drop calculations). •

External Diameter. The outside diameter of the tubing.

•

Absolute Roughness. The Roughness of the tubing.

•

Flow Configuration. Select Tubing, Annulus or Tubing & Annulus.


Adding Casing This option is used to add a length of Casing to the well. A WellFlo model can have none, one or any number of Casing components. The Casing and Tubing components also can be mixed in any order, should the need arise. The only difference between a Casing and Tubing is that the latter is considered to have an external Casing. This detail is significant for Heat Transfer modeling and for the Annular Flow option; otherwise for nodal analysis calculations, both component types are just regarded as tubulars, where multi‐phase flow is concerned. To model an open hole completion or a slotted liner completion, choose Casing components, and enter an appropriate name in the Node Name field.

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CONFIGURATION Adding Casing

If more than one layer is configured in the Reservoir Layers Data configuration screen and a different mid‐perforation depth is assigned to each layer, a length of Casing will automatically be added to the well description between each pair of layers. The Casing components may also be replaced by Tubing components where required.

TO ADD CASING: 1 Open the Configuration menu in the Navigator. 2 Select Equipment under Wellbore in the Model Navigator. The Wellbore Equipment configuration screen is opened in the main content pane. 3 Open the Casing tab (see Figure 2‐25). Figure 2-25: Wellbore Equipment - Casing

4 Select the data type, Length or Depth, from the Enter Data For section.


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CONFIGURATION Adding Restrictions

5 Insert new rows into the table, as necessary. 6 Fill in the following table data: •

Name. A name to describe the casing component.

•

Start Point Measured Depth. The length from the wellhead (or the end of the previous segment) to the downstream end of this segment. The Segment Length field is recalculated as follows: Total Length from Wellhead minus the total length to the end of the previous casing segment.

•

End Point Measured Depth. The True Vertical Depth increment of the

downstream end of the casing segment relative to the upstream end of the casing segment. The Segment Length field is recalculated if the new True Vertical Depth increment is greater than the current Segment Length. In this case, the Segment Length is set equal to the True Vertical Depth increment. •

Segment Length. The length of the casing segment.

•

Internal Diameter. The internal diameter of the casing (used in conjunction with Roughness in the pressure drop calculations).

•

External Diameter. The outside diameter of the casing.

•

Absolute Roughness. The Roughness of the casing.


Adding Restrictions This option is used to add a Restriction to the well. A Restriction is a real node and has an associated pressure drop. It is possible to have more than one Restriction in a well. A Restriction is a component of reduced diameter in the completion and the actual data required for a Restriction are the same as that for a Sub‐surface Safety Valve or Surface Choke in a well (i.e. Flow Restriction (ID) and (optionally) Upstream Temperature and Node Name).

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This component is assumed to have zero length.


CONFIGURATION Adding Restrictions

TO ADD RESTRICTIONS: 1 Open the Configuration menu in the Navigator. 2 Select Equipment under Wellbore in the Model Navigator. The Wellbore Equipment configuration screen is opened in the main content pane. 3 Open the Restrictions tab (see Figure 2‐26). Figure 2-26: Wellbore Equipment - Restrictions

4 Insert new rows into the table, as necessary.


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CONFIGURATION Adding Trace Points

5 Fill in the following table data: •

Name. A name to describe the Restriction.

•

Equipment Type. Select Restriction or SSS Valve.

•

Measured Depth. The length from the Wellhead to the downstream end of

this Restriction. •

Internal Diameter. The Internal Diameter of the Restriction.

•

Critical Flow. Check to use the Critical Flow equation for the pressure loss through the Restriction, otherwise a sub‐critical calculation will take place.

At a sufficiently high Gas/Liquid Ratio (GLR), a choke will ignore this checkbox and switch smoothly between sub‐critical and critical flow depending on local conditions. The facility to use the Critical Flow equation is only important for Black Oil systems, or Gas, Gas Condensate and Volatile Oil systems with low GLRs (<10,000 scf/STB). For critical flow, users can select the Flow Correlation to use for the computation of upstream pressure at the choke in the Flow Correlations configuration screen (see “Flow Correlations” on page 65). For Gas, Gas Condensate and Volatile Oil systems with high GLRs (>10,000 scf/STB), the checkbox is ignored and a general critical/sub‐critical single‐phase gas equation is used.

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Regardless of the situation, WellFlo always checks whether flow is critical or not (applying a sonic velocity criterion), and reports this as a Flow Regime Number (1 = critical, 0 = sub-critical), in the Analysis.Log file.


Adding Trace Points This option is used to add additional data points to the well. A Trace Point is a node with an associated measured depth that can be selected as a Calculation Node in Nodal Analysis (see “Calculation Nodes” on page 217).

TO ADD TRACE POINTS: 1 Open the Configuration menu in the Navigator.

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CONFIGURATION Adding Trace Points 2 Select Equipment under Wellbore in the Model Navigator. The Wellbore Equipment configuration screen is opened in the main content pane. 3 Open the Trace Points tab (see Figure 2‐27). Figure 2-27: Wellbore Equipment - Trace Points

4 Insert a new row into the table to add a trace point. 5 Enter a Name and Measured Depth for the trace point. 6 Click Apply to save your changes. 7 Click Forward to advance to the next configuration screen.


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CONFIGURATION Surface Terrain Data

SURFACE TERRAIN DATA The Terrain Data configuration screen is used to view, enter and edit Surface Deviation data. The convention for Surface Component measurement is different from the well components. Instead of Depth, WellFlo deals here with the more useful concept of Elevation; these are measured above the permanent datum of Mean Sea Level (MSL). Referring to Figure 2‐28, the Elevation of a Component is the vertical Elevation above MSL of the end of the pipe furthest away from the Wellhead. Elevation Increment is the change in Elevation over the Component itself. The first Flowline will have an Elevation Increment (i.e. labeled 1 in the illustration) equal to the Component Elevation minus the Wellhead Elevation. From this point on, the Elevation Increments will be measured as the differences between component ends. Figure 2-28: Schematic of Elevation Convention

Figure 2‐29 shows the conventions for Total Length from the Wellhead and Elevation. Referring to this illustration, users will see that the equivalent of TVD in the Well is Elevation (above MSL). The equivalent of Measured Depth in the Well is Total Length, measured from the Wellhead, and the equivalent of Depth Increment is Length Increment. In the upper part of Figure 2‐29, four Flowline nodes are shown. The numbers on the right, aligned with the broken lines, show the Elevation (MSL) of each Node, measured at the downstream end in each case.

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The Elevation Increment of each Node is measured from the previous Node. These would be positive for Nodes 1 and 2, zero for Node 3 (horizontal) and negative for Node 4 (downward). The Length Increments are the actual Pipe Lengths. In the lower part of Figure 2‐29, the same Nodes are shown, but this time with Total Lengths. These are always measured from the Wellhead. Figure 2-29: Schematic of Flowline Elevations and Lengths

Figure 2‐30 shows the convention for specifying the Angle of Inclination from vertical for Surface Pipelines.

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Since downward flow is also possible, care must be taken in assigning a value.


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Figure 2-30: Surface Pipeline Deviation Convention

A deviation of 0° means vertical upward flow; 0° to 90° means inclined upward flow; 90° means horizontal flow; 90° to 180° means inclined downward flow, and 180° means vertical downward flow. To navigate through the table, the cursor can be moved with the keyboard arrow, TAB, PAGE UP, PAGE DOWN, HOME and END keys, or the mouse can be clicked on the desired field, using the scroll bar when necessary. The currently selected field has a dashed border, and new data can be entered. When users have finished editing a field, select the Tab key to confirm the edit and move to the next field for editing, or click directly onto the next field. Select the ESC key to abort an edit.

TO ENTER TERRAIN DATA: 1 Open the Configuration menu in the Navigator. 2 Select Terrain Data under Surface Data in the Model Navigator. The Terrain Data configuration screen is opened in the main content pane (see Figure 2‐31).

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CONFIGURATION Surface Terrain Data Figure 2-31: Terrain Data

3 Check Angle to enable the Deviation from Horizontal field. 4 Select radio buttons from the Enter Data For section to show or hide those parts of the table. 5 Insert new rows into the table, as necessary.


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CONFIGURATION Surface Equipment

6 Fill in the following table data: •

Distance from WH. The distance from the Wellhead.

•

Segment Length. Each Length from the Wellhead, in ascending order. The corresponding Elevation field is updated automatically.

•

Elevation. Each Elevation from Wellhead corresponding to the Segment Length entered. The corresponding Deviation from Horizontal field is

updated automatically. •

Elevation Increment. The Elevation minus the Elevation at the end of the

previous segment. •

Deviation from Horizontal. Enter each angle corresponding to the Segment Length entered. The corresponding Elevation field is updated

automatically. 7 Click Apply to save your changes. WellFlo will translate the tabular terrain data into an equivalent string of nodes in the Terrain data chart. 8 Click Forward to advance to the next configuration screen.

SURFACE EQUIPMENT The Surface Equipment configuration screen is used to view, enter and edit Surface Equipment Data. This dialog can be used to specify the following items of Surface equipment: Bend, Choke, Downcomer, Flow Line, Gauge, Manifold or Riser. To navigate through the table, the cursor can be moved with the keyboard arrow, TAB, PAGE UP, PAGE DOWN, HOME and END keys, or the mouse can be clicked on the desired field, using the scroll bar when necessary.

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The currently selected field has a dashed border, and new data can be entered. When users have finished editing a field, select the Tab key to confirm the edit and move to the next field for editing, or click directly onto the next field. Select the ESC key to abort an edit.

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This dialog operates in a similar manner to the Well Equipment configuration screen (see “Wellbore Equipment” on page 102), except, where that screen uses Measured Depth, this screen uses length from Wellhead. Remember for Surface Equipment, the term Node refers to the end of the component farthest from the Wellhead/Xmas Tree.

TO ADD SURFACE EQUIPMENT: 1 Open the Configuration menu in the Navigator. 2 Select Surface Equipment under Surface Data in the Model Navigator. The Surface Equipment configuration screen is opened in the main content pane (see Figure 2‐32).


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Figure 2-32: Surface Equipment

3 Insert new rows into the table, as necessary. 4 Fill in the following table data: •

Name. A name to describe and identify the component.

•

Type. The type of component to be placed at the associated depth. Choices include from Manifold, Choke, Surface ESP, FlowLine, Bend, Riser, Downcomer, Gas Injector, Wellhead Gauge or TracePoint.

•

Start from WH. The starting length from the Wellhead of each component, in any order. For Flow Lines, enter the length to the downstream end.

•

End from WH. The ending length from the Wellhead of each component, in

any order. •

Length. The total length of the component, calculated from the Start from WH and End from WH fields.

5 For the following components, enter additional equipment details:

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Choke — Diameter. The Internal Diameter of the Choke. — Use Critical flow. Check to use the critical flow equation for the pressure loss through the Choke, otherwise a sub‐critical calculation will take place. At a sufficiently high Gas/Liquid Ratio (GLR), a choke will ignore this checkbox and switch smoothly between sub‐critical and critical flow depending on local conditions. The facility to use the Critical Flow equation is only important for Black Oil systems, or Gas, Gas Condensate and Volatile Oil systems with low GLRs (<10,000 scf/STB). For critical flow, users can select the Flow Correlation to use for the computation of upstream pressure at the choke in the Flow Correlations configuration screen (see “Flow Correlations” on page 65). For Gas, Gas Condensate and Volatile Oil systems with high GLRs (>10,000 scf/STB), the checkbox is ignored and a general critical/sub‐critical single‐phase gas equation is used.

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Regardless of the situation, WellFlo always checks whether flow is critical or not (applying a sonic velocity criterion), and reports this as a Flow Regime Number (1 = critical, 0 = sub-critical), in the Analysis.Log file.


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Surface ESP

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All options pertaining to WellFlo-ESP will be disabled if the current software license is not configured for WellFlo-ESP. The ESP and GLV options are separately licensed options within WellFlo; users with a basic WellFlo license will not have access to these facilities.

Pump Environment: — Length From Wellhead. This represents the Length from Wellhead at which the Surface ESP is situated. — Max Equ’t O.D. The maximum Outside Diameter (OD) of Pump and Motor to be used. Normally the maximum will correspond to the Casing Inside Diameter (ID) minus the clearance for Cable that is required.

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This field should not exceed the Casing Inside Diameter (ID) at this point in the Well or anywhere between this point and the Wellhead.

— Min. Equ’t O.D. The minimum Outside Diameter (OD) of pump and motor to be used.

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This field should be set to zero if a minimum is not to be enforced.

Some Pump/Motor combinations have different nominal Outside Diameters (ODs). For example, Pumps of 3.372" and 3.996" both work with 3.75" Motors. To ensure that only one of these Pump/Motor combinations are selected, users would need to enter a minimum/maximum of 3.3"/3.8", or 3.7"/4" respectively.

— Operation Frequency. The Operating Frequency for the pump and motor. In Analysis Mode, users will see the effects of varying the frequency on the pump performance. — Pump Name. A name to describe the component.

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Wear Factors/Efficiencies: — Pump wear factor. A value to allow for the degradation of the pump stages due to such factors as scaling, stage abrasion, etc. The Pump Wear Factor is a modifier to the pump performance. When it is 1.0, no modification is made. When it is less than 1.0, the pump performance is degraded, as controlled by the Head Factor or Power Factor buttons. — Power factor. Select this option to increase the Pump Power Input Requirement by the Pump Wear Factor. The Pump Head remains unmodified, but the Pump Power Input Requirement is multiplied by 1/Pump Wear Factor. This can be used to approximate the extra power taken up by a gas separator. — Head factor. Select this option to decrease the Pump Head by the Pump Wear Factor (i.e. the Pump Head produced at a given flow rate (from the performance curve) is multiplied by the Pump Wear Factor, and Pump Power Input Requirement remains unmodified). This would normally be the case for a worn pump.

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For example, a Pump Wear Factor of 0.8 could either degrade the Pump Head to 80% of the manufacturer's figure, or increase the Pump Power Input Requirement needed to (1/0.8) = 125% of the manufacturer's figure.

— Motor wear factor. A value to allow for the degradation of the motor itself due to such factors as overloading, cable wear, etc. This value will decrease the efficiency of the motor, thereby increasing the power it requires. The Motor Wear Factor is a modifier to the motor current required for a given power. It has the effect of increasing the heat dissipation of the motor, since any excess power will be dissipated as heat.

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For example, if a value of 0.9 is entered here, the motor current for a given power requirement is increased to (1/0.9) = 111% of the unmodified figure. The excess (11% in this case) is dissipated as heat.

— Gas Separator Present. Check if a Gas Separator is being used below the motor to remove free gas. If this option is selected, the Separator Efficiency field is enabled for input.


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— Separator Efficiency. This field is enabled if the Gas Separator Present checkbox is checked and is used to input the fraction of free gas at the ESP intake conditions that will be split off from the well stream and assumed to be vented up the annulus (e.g. if the efficiency is set at 0.75, 75% of the free gas will be split off from the stream). Design Pump Only/Analyze Pump: — Select the Design Pump Only to design an ESP. When selected, the Analysis Equipment section is grayed‐out (disabled) and normal nodal analysis calculations will treat the pump as non‐existent, so users can then perform ESP Design to find a suitable pump. — Select Analyze Pump to model an existing pump, and choose pump characteristics from the underlying drop‐down menu fields.

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Analysis Equipment: In Analysis mode, this section is enabled and the ESP and motor can be edited. There are three cases when this is required: — To enter pump and motor data without performing an ESP Design first (e.g. to model an existing well) — To change the pump selection at any time — When a pump and motor have been selected at the end of a Design mode run, users can review the selected pump before proceeding (e.g. this may be done to modify the number of stages or the motor nameplate rating). — Pump Model. Select a pump to be analyzed. The list of pumps is arranged by Manufacturer and each entry contains a Model Name and Manufacturer Name (e.g. A230 ‐ Reda).

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Only Pumps with ODs between the Min/Max Equipment OD specified in the Pump Environment section will be shown. If no Pumps exist in the range specified, the Pump Model field will be blank.

— Min/Max flow rate. These fields display the manufacturerʹs minimum and maximum recommended in‐situ total flow rates through the pump. These fields are linked to the Operation Frequency field specified in the Pump Environment section and show the actual rating at the frequency entered (e.g. if users have the first pump in the database selected, the A230‐Reda, then at 60Hz, it has a recommended flow capacity range of 100‐350 bbl/day. If users change the frequency to 66Hz (+10%), the range shows 110‐385 bbl/day (also +10%)).

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Users are advised to contact the Pump Manufacturer before operating a pump outside its recommended range.

— Number of stages. The number of stages to operate the pump at. Enter a suitable value between the minimum and maximum number allowed for this pump. — Motor model. The motor model to power the pump. The Models presented are constrained by the Min/Max Equipment OD specified


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in the Pump Environment section. The list includes all motors that satisfy the OD range; it is not restricted by the pump Manufacturer. — Nameplate rating. The nameplate rating for the motor. All the motor nameplate specifications possible for the motor series currently selected are listed in this drop‐down list. It will default to the first nameplate on the list if a new Motor series is selected (i.e. 60Hz rating). — Operating Rating. The nameplate rating selected, modified by the Operating Frequency specified in the Pump Environment section. This enables users to select a Nameplate Rated Motor from the list (at the manufacturersʹ design frequencies), whilst also viewing the actual nameplate rating the motor will have at the user‐defined Operating Frequency (e.g. if an Operating Frequency of 66 Hz has been specified and the first pump and motor in the database are selected, the A230‐Reda and 375 Series‐Reda with Nameplate Rating 7.5 hp, 410 V, 14A, the Operating Rating will not be 7.5 hp, 410 V, 14A at 60Hz, but 8.25 hp, 451 V, 14A at 66Hz (i.e. 10% higher power and terminal voltage at the same current). — Cable Size. The standard cable size required to carry power down to the pump.

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The Voltage Loss/Amp/1000 ft for each Cable Size is stored in a file espcable.dat. Users can edit the values or add new cable sizes, if required. However, the values entered must be in Volts/Amp/1000 ft, regardless of the unit system being used. A maximum drop of 30V/1000ft is usually recommended.

— Plot. Plots the ESPʹs Performance Curve, at the user‐defined Operating Frequency and Number of Stages, to give an approximation of how the pump may perform during full nodal analysis. The Plot displays:

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•

Head on the left axis.

•

Power (Motor Load) on the right axis.

•

Minimum and Maximum Flow Rates as vertical dashed lines, with Flow Rate as the abscissa.

•

The Title shows the Pump Name, Design Stages and Operating Frequency for which the Plot is valid.



Flowline Flowline Details: — Inside Diameter. The Internal Diameter (ID) of the Flow Line (used in conjunction with Roughness in the pressure drop calculations). — Outside Diameter. The Outside Diameter (OD) of the Flow Line (used in the calculated, calibrated and coupled Temperature Model calculations). — Roughness. The roughness of the Flow Line. — Insulation Diameter. The diameter of the insulation surrounding the Flow Line. If the Flow Line is not insulated, then enter a diameter of 0 (used to calculate the Heat Transfer Coefficient — if required). — Replication Factor. Only enter a number greater than 1 if this component is actually one of several identical components in parallel. WellFlo will calculate Frictional Effects and Heat Loss in this component based on the corresponding fraction of the actual flow rate. This allows users to model several identical parallel Flow Lines, while only entering parameters for one (e.g. a value of 2 will split the flow stream into two halves (with corresponding adjustments to flow regimes, frictional losses, heat transfer, etc.), because of the reduced fluid velocities and increased flow surface area associated with two Flowlines).

Bend Bend Details: — Inside Diameter. The Internal Diameter (ID) of the Bend. — Roughness. The roughness of the Bend. — Total bend angle. The total bend angle (e.g. 90° for a right angle, 180° for a U‐turn, etc.). — Bend radius. The radial distance from the center of the bendʹs arc to its axial mid‐line. A value less than half of the inside diameter is therefore impossible.


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Riser Riser Details: — Inside Diameter.The Internal Diameter (ID) of the Riser (used in conjunction with Roughness in pressure drop calculations). — Outside Diameter. The Outside Diameter (OD) of the Riser (used in the calculated, calibrated and coupled Temperature Model calculations). — Roughness. The roughness of the Riser (used with ID in pressure drop calculations). — Insulation Diameter. The diameter of the insulation surrounding the Riser. If the Riser is not insulated, then enter a diameter of 0 (used to calculate the Heat Transfer Coefficient ‐ if required). — Replication Factor. Only enter a number greater than 1 if this component is actually one of several identical components in parallel. WellFlo will calculate Frictional Effects and Heat Loss in this component based on the corresponding fraction of the actual flow rate. This allows users to model several identical parallel Risers, while only entering parameters for one (e.g. a value of 2 will split the flow stream into two halves (with corresponding adjustments to flow regimes, frictional losses, heat transfer, etc.), because of the reduced fluid velocities and increased flow surface area associated with two Risers).

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Downcomer Downcomer Details: — Inside Diameter.The Internal Diameter (ID) of the Downcomer (used in conjunction with Roughness in pressure drop calculations). — Outside Diameter. The Outside Diameter (OD) of the Downcomer (used in the calculated, calibrated and coupled Temperature Model calculations). — Roughness. The roughness of the Downcomer (used with ID in pressure drop calculations). — Insulation Diameter. The diameter of the insulation surrounding the Downcomer. If the Downcomer is not insulated, then enter a diameter of 0 (used to calculate the Heat Transfer Coefficient ‐ if required). — Replication Factor. Only enter a number greater than 1 if this component is actually one of several identical components in parallel. WellFlo will calculate Frictional Effects and Heat Loss in this component based on the corresponding fraction of the actual flow rate. This allows users to model several identical parallel Downcomers, while only entering parameters for one (e.g. a value of 2 will split the flow stream into two halves (with corresponding adjustments to flow regimes, frictional losses, heat transfer, etc.), because of the reduced fluid velocities and increased flow surface area associated with two Risers).

Gas Injector

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This component is only available if WellFlo-Gas-Lift is enabled.

A Gas‐Injector defines a point where lift‐gas enters the system above the Wellhead (e.g. at the foot of a Riser). It is a virtual node in that it is not assigned a finite length and does not have a pressure drop (along the well) associated with it.


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A Gas‐Injector cannot be specified for a Gas or Gas Condensate well or if there is an ESP present in the well system. Gas Injector Details: — Injection gas gravity. The gravity of the injected gas. This value is distinct from the gravity of the gas injected at Gas‐Lift Valves in the well, or at any other surface injector. — Gas injection rate. The rate at which the selected injector operates.

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The input of the gas is not modeled in the same way as with downhole Gas-Lift Valves (see “Gas Lift Data Configuration” on page 284). In this case, it is assumed that the specified Gas Rate can be injected at that point, regardless of Gas-Injection Pressure. The values entered for Injection gas gravity and Gas injection rate are handled separately in WellFlo from the calculations for sub-surface Gas-Lift Valves, allowing users to specify a different Injection Gas Gravity for these nodes.


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CONFIGURATION References

REFERENCES 1 Furnival, S.R. and Baillie, J.M.: ʺSuccessful Prediction of Condensate Wellbore Behaviour Using an EoS Generated From Black Oil Dataʺ. Offshore European Conference, Aberdeen, Sept. 1993: Paper SPE 26683. 2 Payne, Palmer, Brill and Beggs; ʺEvaluation of Inclined Liquid Holdup and Pressure‐Loss Correlations Using Experimental Dataʺ, JPT, September 1979. 3 Turner, R.G.: ʺAnalysis and Prediction of Minimum Flow Rate for the Continuous Removal of Liquids from Gas Wellsʺ; JPT, Nov. 1969, Trans. AIME 246. 4 Coleman, S.B., Clay, H.B., McCurdy, D.G., and Norris III, H.L.: ʺA New Look at Predicting Gas‐Well Load‐Upʺ; JPT, March 1991. 5 Glasø, O.; ʺGeneralized Pressure‐Volume‐Temperature Correlationsʺ, JPT, 785‐795, May 1980. 6 Lasater, J.A.; ʺBubble‐Point Pressure Correlationʺ, Trans. AIME, 213, 379‐381, 1958. 7 Standing, M.B.; ʺA Pressure‐Volume‐Temperature Correlation for Mixtures of Californian Oils and Gasesʺ, Drill. and Prod. Prac., API, 275‐285, 1947. 8 Vasquez, M. and Beggs, H.D.;ʺCorrelations for Fluid Physical Property Predictionʺ, JPT, 968‐970, June 1980. 9 Petrosky, G.E. and Farshad, F.F.; ʺPressure‐Volume‐Temperature Correlations for Gulf of Mexico Crude Oilsʺ, SPE 26644, Proc. of 68th. Ann. Conf., 395‐406, 1993. 10 Macary S.M. and El‐Batanoney M.H. (Egyptian Petroleum Research Institute); ʺDerivation of PVT Correlations for the Gulf of Suez Crude Oilsʺ, Journal of the Japan Petroleum Institute (formerly the Sekiyu Gakkaishi‐Journal of the Japan Petroleum Institute), Vol. 36, No. 6, 1993. 11 Beal, C.; ʺThe Viscosity of Air, Water, Natural Gas, Crude Oil and its Associated Gases at Oilfield Temperatures and Pressuresʺ, Trans. AIME, 165, 94‐115, 1946. 12 Chew, J. and Connally, C.A.; ʺA Viscosity Correlation for Gas‐Saturated Crude Oilsʺ, Trans. AIME, 216, 23‐25, 1959.


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CONFIGURATION References

13 Beggs, H.D. and Robinson J.R.; ʺEstimating the Viscosity of Crude Oil Systemsʺ, JPT, 27, 1140‐1141, 1975. 14 Carr, N.L., Kobayashi, R. and Burrows, D.B.: ʺViscosity of Hydrocarbon Gases under Pressureʺ. Trans AIME 201 (1954), pp 264‐272. 15 Lee, A.L., Gonzalez, M.H. and Eakin, B.E.: ʺThe Viscosity of Natural Gasesʺ. J. Pet. Tech. 18 (1966), pp 997‐1000. 16 McCain, W.D. Jr.: ʺProperties of Petroleum Fluidsʺ. 2nd edition, 1990. 17 ʺCRC Handbook of Chemistry and Physicsʺ. 1st Student Edition, 1988. 18 Brill, J.P. and Beggs, H.D.: ʺTwo‐Phase Flow in Pipesʺ, University of Tulsa, 1986. 19 Standing, M.B.: ʺVolumetric and Phase Behaviour of Oil Field Hydrocarbon Systemsʺ. SPE Monograph series, 1977. 20 Sutton, R.P. and Farshad, F.F.: ʺEvaluation of Empirically Derived PVT Properties for Gulf of Mexico Crude Oilsʺ. 59th annual technical conference, Houston, Sept. 1984: Paper SPE 13172.

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Chapter 3 RESERVOIR LAYERS This chapter explains how to configure Reservoir Layer parameters in WellFlo. Reservoir Layers ............................................................................ 130 Setting General Parameters ...................................................... 131 Segmented IPR Model ............................................................... 138 Configuring Drainage Geometry ............................................. 140 Plotting IPR/IIR .......................................................................... 149 Adding to Plots ........................................................................... 151 Plotting Composite IPR ............................................................. 153 Relative Permeability ................................................................. 157 Skin Analysis .................................................................................. 167 Skin Analysis: Completion (Vertical) ...................................... 167 Calculations (Vertical) ............................................................... 173 Skin Analysis: Completion (Horizontal) ................................ 175 Calculations (Horizontal) .......................................................... 180 Skin Analysis: Completion (Fractured) .................................. 183 Calculations (Fractured) ............................................................ 189 References ....................................................................................... 190


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RESERVOIR LAYERS Reservoir Layers

RESERVOIR LAYERS The following functions can be performed via this configuration screen: •

Select from a choice of IPR Calculation Models for each Layer in the Reservoir.

•

Plot and Print the Layer IPRs.

•

Export Layer Pseudo‐Pressure Data.

•

Import an external Pseudo‐Pressure Data File.

•

Enter/Edit Tabulated Inflow Data.

Together with a choice of industry‐standard IPR Calculation Models, and a Tabular Inflow Data entry option, the EPS Normalized Pseudo‐Pressure method is also available. This theoretically rigorous method can be used for all Fluid Types (i.e. Oil, Gas or Condensate). The ʺclassicalʺ Calculation Models assume Single‐Phase Flow or treat Multi‐Phase Flow simplistically, and in the case of Liquids, assume constant Fluid Properties at all Pressures. However, the Normalised Pseudo‐Pressure method (y(p)), accounts for the following at all Pressures: •

Up to three Flowing Phases (i.e. Oil, Gas, Water)

•

The corresponding Pressure‐Dependent Fluid Properties (i.e. Volume Factors, Viscosities and Densities)

•

The Relative Permeability of each Flowing Phase at changing Saturations.

Therefore, if the IPR is calculated using y(p), fluid behaviour is modeled more accurately, including Liquid Dropout in Condensate systems.

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IPR uses the Fluid Properties sub-system (refer to “Fluid Parameters” on page 73), dynamically to obtain the Fluid Properties for each Layer (e.g. in a Condensate Reservoir, the EoS will be called at each Pressure while computing the IPR Curve). The Absolute Open Flow (AOF) potential is (in all cases), computed at a Pressure of 14.65 psia or equivalent.


RESERVOIR LAYERS Setting General Parameters

The Layer Parameters tab, under the Reservoir Layers Data configuration screen, it is used to enter or edit Layer Parameter data for individual Layers in the Well Model.

Setting General Parameters TO SET GENERAL PARAMETERS: 1 Open the Configuration menu in the Navigator. 2 Select Reservoir from the Model Navigator. A new layer is opened in the Reservoir Layers Data configuration screen in the main content pane (see Figure 3‐1). Figure 3-1: Reservoir Layers Data - General

3 Enter a Name for the layer.


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4 Check Active to make the currently selected layer active; otherwise, it will be inactive. Inactive layers will be excluded from composite reservoir IPR calculations and from nodal Analysis. 5 Enter values for the following General parameters: • •

Pressure. The average Shut‐In Pressure of the Layer. Temperature. The average Temperature of the Layer (i.e. away from the

Wellbore). •

Midperf Depth. The Measured Depth to the Fluid Entry Point (i.e. conventionally the middle of the Perforations). This defaults to the maximum Tubing Depth or Casing Depth in the system description.

•

Permeability. This is conventionally the Permeability to the Hydrocarbon

Phase at Irreducible Water Saturation (Swi), not the Absolute Rock Permeability. It is assumed to be the same in the x‐direction and y‐direction; in the event of Areal Anisotropy, use: Figure 3-2:

•

Thickness. The net Formation Thickness (i.e. normal to Dip).

•

Wellbore Radius. The Openhole Wellbore Radius (rw), into this field (i.e. not the Casing ID).

•

Relative Injectivity. This field is only available for Production Wells. Enter the ratio of the Injectivity Index (i.e. when the Wellbore Pressure is greater than the Layer Pressure) to the Productivity Index. This specifies the ability of the Layer to receive cross‐flowing fluid.

A default value of zero indicates that at a Wellbore Pressure greater than the Layer Pressure, the Layer will simply shut‐off.

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Other values indicate that at a Wellbore Pressure greater than the Layer Pressure, the fluid produced from other Layers now flows into this Layer. A Straight Line IIR Model applies, with an Injectivity Index which in principle is the specified multiple of the Productivity Index. Multipliers of around 0.6 are common in practice.

i

This fraction is mass based, rather than volumetric.

Cross‐Flow between Layers at Reservoir Depth is always allowed. In other circumstances, the Layer with the higher Pressure must be ʺbelowʺ the Cross‐Flowing Layer (as illustrated below left) in the sense that it is at a greater Measured Depth (MD). In a model with inverted tubing (as illustrated below right), the higher Pressure Layer could be at a lesser Total Vertical Depth (TVD), and therefore may lie ʺaboveʺ the Cross‐Flowing Layer in terms of the Well Schematic in WellFlo. The Relative Injectivity must also be set to a non‐zero value in order for Cross‐Flow to occur (WellFlo defaults this parameter to zero and with this status Cross‐Flow will not occur, even if the Layers are ordered correctly).


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Figure 3-3: Cross-Flow Between Layers

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The analog of cross-flow is not modeled for Injection Wells. At a Wellbore Pressure below the Layer Pressure, the Injection Layer simply shuts-off.

•

Parting Pressure. (Only available for Injection Wells.) The Pressure at which the Formation breaks down under Injection. In WellFlo, the IIR Curve will be assigned a very large Injectivity Index at Injection Rates higher than the Rate corresponding to the Parting Pressure. This provides a simplistic representation of Formation Fracturing at high Rates.

•

Water Cut. Enter the Water‐Cut.

•

Gas-Oil Ratio. Enter the Gas‐Oil Ratio.


RESERVOIR LAYERS Setting General Parameters 6 Select an IPR Model. Depending on the currently selected Fluid Type, the following Models are available for Producers (Injectors are discussed in “IIR Calculation Models (Injectors):” on page 137). •

Straight Line. This uses a constant Productivity Index (J), assuming Inflow is directly proportional to Drawdown at all Pressures.

•

Vogel. This uses a Straight Line Productivity Index (J), above the Bubble‐Point and the Vogel relationship below (where interstitial Gas has evolved).


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The published form of the Vogel equation uses Coefficients 0.2 and 0.8. A different Coefficient can be ʺforced,ʺ by entering a value in the Coefficient of P in Vogel Equation field to replace the default value of 0.2. The second Coefficient in the equation will automatically be taken as 1.0 minus the entered value.

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In both Straight Line and Vogel models, when the Layer Parameters option is used to compute a theoretical (J), the required Fluid Properties are calculated at the Layer Pressure, and the Relative Permeability data are invoked: if the specified Water-Cut is zero, (J) is calculated using End-Point Relative Permeability kro(Swi) (= 1.0 conventionally); for a non-zero Water-Cut, it uses kro(Sw) and krw(Sw).

•

Fetkovich. The empirical C and n Method, available for Oil. This requires input of a C-coefficient and an n-exponent.

•

Normalized Pseudo Pressure. This incorporates the Fluid Properties of

each Flowing Phase — Gas, and Water if a non‐zero WGR has been specified for the Layer — and the Relative Permeabilities (krg, krw) of each Phase at the appropriate Saturation, across the range of Pressures from Atmospheric up to Layer Pressure.

i •

The declared value of (B) is computed at Layer Pressure.

Normalized Pseudo Pressure External. This is used to Import an

externally‐generated Normalized Pseudo‐Pressure file. •

p2-form. This model is available for Dry Gas types. This provides a direct

method for computing Single‐Phase Gas Deliverability Curves. It is only available for Single‐Phase Gas (WGR = 0).

i •

The p2 approximation is best suited to Pressures below about 2000 psia.

Back Pressure. This model is available for Dry Gas types. This is the

empirical Fetkovich C‐and‐n Model and is only available for Single‐Phase

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Gas (WGR = 0).

i •

The p2-form and Back Pressure (C and n) options will not be available if a non-zero WGR has been specified in the Fluid Parameters configuration screen for the Layer.

IIR Calculation Models (Injectors): The description of the IPR Calculation Models also applies to the calculation of the IIR for Injection Wells, with the following differences: — Water: The Straight Line, Normalized Pseudo‐Pressure and Normalized Pseudo Pressure (external) options are the only ones available. — Gas: The Normalized Pseudo‐Pressure and Normalized Pseudo Pressure (external) options are the only ones available. For Plotting the IIR Curve, the IIR is computed over pressures above Layer Pressure, using J and F (Water), or B and F (Gas), up as far as the specified Formation Parting Pressure. At higher Injection Rates, the IIR Curve is flattened (effectively a very large J or very small B), to approximate the effect of Formation Breakdown. The value displayed under AOF is the critical Injection Rate for Formation Breakdown, and corresponds to the Formation Parting Pressure (also refer to “Plotting IPR/IIR” on page 149).

7 Check Include non-Darcy effects to control whether or not to include Non‐Darcy Effects in the Skin calculations. By default, Gas and Condensates do include them, but Oil does not. 8 Check Use calculated skin to disable the Total Darcy Skin and Total Non-Darcy Skin fields, enable the Fractured checkbox and use calculated Total Skin components. When checked, a Skin tab is added to the Reservoir configuration screen. 9 Check Fractured to apply the Fractured Skin Analysis Completion Model. This model is configured under the Skin tab (see “Skin Analysis: Completion (Fractured)” on page 183).


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RESERVOIR LAYERS Segmented IPR Model

10 For Test data mode, enter Test Point Data: •

Test Pressure 1. The Pressure at the first Test Point.

•

Test Flow Rate 1. The Flow Rate at the first Test Point.

•

Include Non-Darcy Effects. Includes or excludes Non‐Darcy Effects in the

calculations. By default, Gas and Condensates include Non‐Darcy Effects and Oil does not. •

Test Pressure 2. The Pressure at the second test point.

•

Test Flow Rate 2. The Flow Rate at the second Test point.


Segmented IPR Model This dialog box is generated when the Segmented button is selected. It is used to divide a Horizontal Well Completion into discrete Segments, to study the effects of Pressure Drop along the length of the completion. An Example Segmented Application is presented at the end of this topic.[?]

TO CONFIGURE SEGMENTED IPR: 1 Open the Configuration menu in the Navigator. 2 Select Reservoir from the Model Navigator. The Reservoir Layers Data configuration screen is opened in the main content pane. 3 Click the Segmented button. The Segmented IPR Model dialog box is displayed (see Figure 3‐4).

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RESERVOIR LAYERS Segmented IPR Model Figure 3-4: Segmented IPR Model

4 Enter values for the following fields: •

Measured depth to heel. The Measured Depth (MD) to the end of the

Completion nearest to the Wellhead. •

Drainage area length. The Length of the Drainage Area.

•

Drainage area breadth. The Breadth of the Drainage Area.

i •

Also refer to the Pseudo-Linear Drainage Area description for a more detailed explanation of the Drainage Area terms in relation to Well Orientation.

Length offset of heel. The distance of the heel from the end of the Drainage

Area opposite the completion (i.e. distance from the heel to the nearest boundary). •

Well length from heel. The Total Completion Length.

•

Number of segments. Enter a Number from 3 to 36.


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RESERVOIR LAYERS Configuring Drainage Geometry

5 Enter the Wellbore radius and associated data in the Layer Parameters area (i.e. Effective permeability, Layer thickness, etc.). These will be applied to all the Segments initially. Users will be able to edit each Segment later and assign different values, if required. There is no need to enter any other data at this stage. 6 Click OK. WellFlo calculates the Mid‐Perforation Depths along the specified well length of the specified Number of segments. It truncates or extends the vertical tubing to the specified Measured Depth (MD) to Heel, then adds horizontal sections of casing of the correct length and diameter to fit between the required Mid‐Perforation Depths.

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If the Well Model has already been configured as a Single-Layer Horizontal Completion in a Rectangular Drainage Area, the default Segmented Model ought to correspond quite closely to it. The Single-Layer Model cannot easily be reconstructed from the Segmented Model, so it should be saved as a separate model if a range of different Segmented Models are to be explored. After Segmentation, the Layer Parameters can be accessed and edited.

Configuring Drainage Geometry This section provides three Drainage Geometry options. The availability of a particular Drainage Geometry option depends on the Well Orientation (refer to “Well and Flow Type” on page 60) and Completion Type (refer to “Skin Analysis” on page 167).

TO CONFIGURE DRAINAGE AREA GEOMETRY: 1 Open the Configuration menu in the Navigator. 2 Select Reservoir from the Model Navigator. The Reservoir Layers Data configuration screen is opened in the main content pane. 3 Open the Geometry tab (see Figure 3‐5).

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RESERVOIR LAYERS Configuring Drainage Geometry Figure 3-5: Reservoir Layers Data - Geometry

4 If necessary, select one of the following flow patterns: •

Pseudo-radial flow. Select this option if a Pseudo‐radial Flow pattern is present around the Well. This option uses a Semi‐Steady‐State Radial Inflow equation to compute the PI.

— For Vertical Wells, the Semi‐Steady‐State Radial Inflow Equation is used to compute the Productivity/Injectivity Index (J) or the Darcy Flow Coefficient (B). — For a Horizontal Well, there is a choice of Semi‐Steady‐State Radial Inflow (derived from Goode and Wilkinson1, or Goode and Wilkinson2 for a single open interval), or Steady‐State (from Joshi3).

i

Pseudo-Radial Flow implies that the Well is a Vertical Line Source, but it can be used for Fractured and/or Horizontal Wells provided the Drainage Radius (or Equivalent Radius if the area has an irregular shape), is at least approximately twice as large as the Length of the Fracture or Horizontal Producing Interval. The Joshi Model for Horizontal Wells puts no such constraint on Well Length and can be used more generally.


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•

Pseudo-linear flow. This option is available only when either:

— A Fractured Vertical Well has been selected and the Drainage Area is small relative to the Fracture Length, such that Pseudo‐linear flow rather than Pseudo‐radial flow is present.

i

This option will also work for a large Drainage Area.

— A Horizontal Well has been selected and a relatively small Drainage Area is present. Three such scenarios include:

•

•

A Well penetrating a small sand lens.

•

A Well completed with several perforated intervals, where each interval drains a section of the Reservoir separated from the next by a real or virtual no‐flow boundary. In this case, each section should be modeled as a separate Unit (Unit = Layer in WellFlo).

•

A Well with several Vertical Fractures, where each Fracture drains a section of the Reservoir separated from the next by a real or virtual no‐flow boundary. Again, in this case, each section should be modeled as a separate Unit.

Constant Pressure Boundary. Select this option if a Horizontal Well has been selected and a Close Constant Pressure Boundary is present, which makes the Drainage Area Shape irrelevant.

— Vertical permeability. Enter the Vertical Permeability of the Layer. — Boundary distance. Enter the distance from the Well Axis to the Constant Pressure Boundary. — Design length (well). Enter the Design or Effective Length of the Horizontal Well. The text appearing here depends on the currently‐selected option in the Length Selection section of “Skin Analysis” on page 167. The design length is the intended Open Interval Length (i.e. for Slotted Liner, Perforations or Openhole). The Effective Length is the actual (producing) Open Interval Length (best estimated from production logging or well testing). 5 For Pseudo-radial flow, select a Drainage Shape and enter all applicable data.

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For Horizontal and Vertical Wells, the Semi‐Steady‐State options include: •

Circular. Select this option for (approximately) Circular Drainage Areas.

— External radius. Enter the external radius of the Drainage Area. This value automatically updates the underlying Drainage area field. — Drainage area. Enter the drainage area. This value automatically updates the overlying External radius field. — Dietz shape factor. Select the Dietz Shape Factor (CA) for the Shape of the Wellʹs Drainage Area and the Wellʹs Position within it; the default value is for a Centrally‐Located Well. •

Rectangular. Select this option for a Rectangular Drainage Area. The only difference between this option and Circular is that it will compute the Dietz Shape Factor (CA) for any Well Position in a Rectangular Drainage Area (Yaxley4). For a Horizontal Well, the Shape Factor refers to an equivalent Vertical Well at its mid‐point. Both options then use the Pseudo‐Radial Inflow Equation to compute the Productivity/Injectivity Index (J) or the Darcy Flow Coefficient (B). Use this option if the Drainage Area is (approximately) Rectangular or if (CA) is unknown. In the case of Fractured or Horizontal Wells, for a Pseudo-radial flow pattern to exist, the Reservoir Dimensions should be several times larger than the Length of the Fracture or Horizontal Producing Interval. It is not, therefore, suited to modeling a Horizontal Well draining a Unit (e.g. a dune body) whose Length in the Well Direction is roughly the same as the Open or Perforated Interval. Nor is it suited to modeling a long Hydraulic Fracture (in a relatively small Drainage Area), or a Fracture close to a Boundary.

— Length, L1. Enter the Drainage Area Length L1 (see Figure 3‐6). — Breadth, L2. Enter the Drainage Area Breadth L2 (see Figure 3‐6). — Length offset. Enter the Well Position in relation to its Length Offset (i.e. distance from boundary in the L1 direction. See Figure 3‐6). — Breadth offset. Enter the Well Position in relation to its Breadth Offset (i.e. distance from boundary in the L2 direction. See Figure 3‐6). — Design Length. Enter the Design or Effective Length of the Well. The Design Length is the intended Open Interval Length (i.e. for Slotted Liner, Perforations or Openhole). The Effective Length is the actual


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(producing) Open Interval Length (best estimated from production logging or well testing). — Drainage area. Displays the (default or calculated) drainage area size. — Dietz shape factor. Displays the (default or calculated) Dietz shape factor (CA) for the shape of the wellʹs drainage area and the wellʹs position within it. Figure 3-6: Drainage Area with Rectangular Geometry

•

Wedge-Shaped. Select this option for Wedge‐Shaped Drainage Areas. This option can be used for cases such as Multi‐Lateral Horizontal Wells draining different segments of the same Unit, or a circular cluster of Vertical Wells.

This option calculates the Dietz Shape Factor (CA), and uses the Pseudo‐Radial Inflow approximation to compute J or B. — Radius of wedge. Enter the Radius of Wedge (see Figure 3‐7). — Angle of wedge. Enter the Angle of Wedge (see Figure 3‐7). — Radius to well. Enter the Well Position in relation to its radius (i.e. distance from the boundary intersection in Figure 3‐7).

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A Horizontal Well section is assumed to lie along a Radius of Wedge, and the Radius to Mid‐Well is measured to the middle of the Producing Interval. For a Vertical Well, this distance is simply the Radius to Well (i.e. Radius to the Wellbore Axis). — Angle of well radius. Enter the Well Position in relation to its Angular Offset (distance from the boundary as illustrated on the diagram below). — Drainage area. This displays the (default or calculated) drainage area size. — Dietz shape factor. This displays the (default or calculated) Dietz shape factor (CA) for the shape of the wellʹs drainage area and the wellʹs position within it.

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The Shape Factor computation for Horizontal Wells (Yaxley4), is valid when the Radius to Mid-Well is less than about 40% of the Wedge Radius. The value is clipped at its theoretical maximum of 31.62 beyond this.

Figure 3-7: Drainage Area with Wedge-Shaped Geometry


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For Horizontal Wells only, the Steady‐State (Joshi) option is available: •

Circular. Select this option for the Joshi Horizontal IPR Model. This geometry would be better described as “elliptical,” because it constructs an ellipse of the same area around the Well, based on the specified External Radius.

For the Horizontal Well (Steady‐State Joshi Model) only, other values on which the Inflow Performance depends are entered in additional fields. Because the Drainage Area is modeled internally as an ellipse of the same area as an equivalent circle, it is possible to specify a Well Length greater than twice the Drainage Radius (this would be treated as a long, narrow ellipse). described as follows: — Nearest Form. Dist. Enter the average Distance from the Horizontal Wellbore Axis to the nearer of the Upper and Lower Boundaries of the currently selected Layer. — Vertical permeability. Enter the Vertical Permeability of the currently selected Layer. — Design Length. Enter the Design or Effective Length of the Horizontal Well. The Design Length is the intended Open Interval Length (i.e. for Slotted Liner, Perforations or Openhole). The Effective Length is the actual (producing) Open Interval Length (best estimated from production logging or well testing). 6 For Pseudo-linear flow, enter all applicable data.

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Hydraulically Fractured Vertical Wells: •

Length, L1. Enter the Drainage Area Length L1 (see Figure 3‐8).

•

Breadth, L2. Enter the Drainage Area Breadth L2 (see Figure 3‐8).

i •

Pseudo-Linear Flow is modeled assuming the Fracture to be aligned with the Length (L1) side of the Drainage Area. There is no need for the Length (L1) to be greater than the Breadth (L2).

Length Offset. Enter the Well Position in relation to its Length Offset (i.e.

distance from boundary in the L1 direction illustrated in Figure 3‐8). •

Breadth Offset. Enter the Well Position in relation to its Breadth Offset (i.e.

distance from boundary in the L2 direction illustrated in Figure 3‐8). •

Fracture Half-Length. Enter the Fracture Half‐Length (i.e. half the total Length of the Fracture).


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Figure 3-8: Pseudo-linear Flow to a Fractured Vertical Well

Horizontal Wells: •

Length, L1. Enter the Drainage Area Length L1 (see Figure 3‐9).

•

Breadth, L2. Enter the Drainage Area Breadth L2 (see Figure 3‐9).

i •

Pseudo-Linear Flow is modeled assuming the Fracture to be aligned with the Length (L1) side of the Drainage Area. There is no need for the Length (L1) to be greater than the Breadth (L2).

Length Offset. Enter the Well Position in relation to its Length Offset (i.e.

distance from boundary in the L1 direction to the nearest end of the Horizontal Producing Interval (i.e. Heel or Toe), illustrated in Figure 3‐9). •

Breadth Offset. Enter the Well Position in relation to its Breadth Offset (i.e.

distance from the Well Axis to the boundary in the L2 direction illustrated in Figure 3‐9). •

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Design Length. Enter the Design or Effective Length of the Horizontal Well. The Design Length is the intended Open Interval Length (i.e. for Slotted Liner, Perforations or Openhole). The Effective Length is the actual (producing) Open Interval Length (best estimated from production logging or well testing).


RESERVOIR LAYERS Plotting IPR/IIR

i

In a Horizontal Well that has been Hydraulically Fractured (i.e. Orthogonal Orientation), the geometrical configuration follows that of the Pseudo-Linear Flow to a Fractured Vertical Well (see Figure 3-8), since the fracture is considered to dominate the Flow Pattern. If the fracture is perpendicular to the well (i.e. Transverse Orientation), the Well Trajectory would in fact be parallel to the Breadth rather than the Length of the rectangle.

Figure 3-9: Pseudo-linear Flow to a Horizontal Well

7 Click Apply to save your selections.

Plotting IPR/IIR Plotting Producers (IPR):

TO PLOT LAYER IPR: 1 Open the Configuration menu in the Navigator. 2 Select Reservoir from the Model Navigator. The Reservoir Layers Data configuration screen is opened in the main content pane. 3 Open the IPR tab. 4 Click Calculate to calculate and plot the IPR curve.


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RESERVOIR LAYERS Plotting IPR/IIR

The Layer IPR Plot is produced from the data you configured (see Figure 3‐10). Figure 3-10: Plotting the Layer IPR (Producing Well)

The Productivity Index (J) coefficient has been calculated using the data from the previous configuration screens and the IPR has been generated using these and the Normalized Pseudo‐Pressure Model to produce an AOF. Plotting Injectors (IIR): The procedure for plotting Injection Well IIR Curves is the same as that for Producers. The IIR Curves are inverted relative to IPRs, and are discontinuous at the Formation Parting Pressure (the plotted curve is in fact terminated here — in Inflow/Outflow Analysis, it will be treated as flat above the critical Injection Rate).

i 150

For a Water Injector, the Straight Line, Normalized Pseudo-Pressure and Normalized Pseudo Pressure (external) options are available. For a Gas Injector, only the Normalized Pseudo-Pressure and Normalized Pseudo Pressure (external) options are available.


RESERVOIR LAYERS Adding to Plots

Adding to Plots You can plot additional IPR curves on the same chart by selecting Keep adding from the chart toolbar. The Plot illustrated below demonstrates how to compare different IPR Calculation Models for a Black Oil system (i.e. the dashed line is the Bubble‐Point Pressure). This type of Plot could be used to compare any data or methods within the Layer IPR section of the program (e.g. different Completions or Skins).

TO ADD PLOTS: 1 With the IPR chart open, select Keep adding from the IPR chart toolbar. 2 Return to the General tab in the Reservoir Layers Data configuration screen. 3 Select a new IPR Model from the drop‐down list, and click Apply. 4 Open the IPR tab and click Calculate to plot the additional IPR curve. An additional plot is added to the IPR chart (see Figure 3‐11).


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RESERVOIR LAYERS Adding to Plots

Figure 3-11: Adding Plots (Producing Well)

5 Mouse over a plot to view a flagged description of the plot’s IPR Model and the coordinate location of your cursor’s current location. 6 Use the chart toolbars to manipulate the IPR plot, create a report or send the plot as an e‐mail attachment. For more information on chart manipulation, sse “Charts” on page 21.

i

The changes you can make between successive plots are not restricted to different IPR Models. You also can change the Layer IPR and Fluid Input Parameters and compare the results.

Plotting Injectors (IIR): The procedure for Plotting Injection Well IIR Curves is the same as that for Producers. The IIR Curves are inverted relative to IPRs and are discontinuous at the Formation Parting Pressure (the Plotted Curve is in fact terminated here — in Inflow/Outflow Analysis, it will be treated as flat above the critical Injection Rate).

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RESERVOIR LAYERS Plotting Composite IPR

IIR Calculation Models (Injectors): The description of the IPR Calculation Models also applies to the calculation of the IIR for Injection Wells. For Plotting the IIR Curve, the IIR is computed over Pressures above Layer Pressure, using J and F (Water), or B and F (Gas), up as far as the specified Formation Parting Pressure. At higher Injection Rates, the IIR Curve is flattened (effectively a very large J or very small B), to approximate the effect of Formation Breakdown. The value displayed under AOF is the critical Injection Rate for Formation Breakdown, and corresponds to the Formation Parting Pressure.

TO PLOT LAYER IIR: 1 Open the Configuration menu in the Navigator. 2 Select Reservoir from the Model Navigator. The Reservoir Layers Data configuration screen is opened in the main content pane. 3 Open the IPR tab. 4 Click Calculate to calculate and plot the IIR curve. The Layer IIR Plot is produced from the data you configured. Use the chart toolbars to manipulate the plot, create a report or send the plot as an e‐mail attachment. For more information on charts, see“Charts” on page 21.

Plotting Composite IPR The Composite IPR function can be used to plot Total Reservoir Production versus Pressure and, optionally, one of the Fluid Ratios versus Production.


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When the Composite IPR button is selected, all the active layer IPRs are combined into a Composite IPR, including the effects of pressure losses between any layers at different depths, and the effects of Cross‐Flow (i.e. if allowed). This will be displayed on the plot as the Composite Performance at Layer X (where X is the name of the shallowest active layer), except when all the layers are at the same depth, when it will be displayed as the Reservoir Performance.

TO PLOT COMPOSITE IPR: 1 Open the Configuration menu in the Navigator. 2 Select Reservoir from the Model Navigator. The Reservoir Layers Data configuration screen is opened in the main content pane. 3 Open the IPR tab. 4 Click the Composite IPR button on the toolbar. The Additional curves menu is added to the IPR chart (see Figure 3‐12).

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RESERVOIR LAYERS Plotting Composite IPR Figure 3-12: Composite IPR

5 Make a selection under Additional curves. Three choices are available and these depend on the currently selected Reservoir Fluid Type as described earlier: •

None. Selects no ratio for plotting.

•

Water Cut. Selects Water‐Cut for plotting against Production.

•

Gas Oil Ratio. Selects Gas/Oil Ratio for plotting against Production.

6 Check Plot Phase Component to Plot the Water and Oil Phase Production against Pressure.

i

This option is available only for a Single-Layer Black Oil Model and allows the Water and Oil Phase IPRs to be plotted in addition to the total Liquid IPR.

7 Click Plot.


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Your selection is plotted on the Composite IPR chart (see Figure 3‐13). Figure 3-13: Composite IPR

8 Mouse over a plot to view a description highlighted in the chart legend as well as to view the coordinate location of your cursor’s current location. 9 Use the chart toolbars to manipulate the IPR plot, create a report or send the plot as an e‐mail attachment. For more information on charts, see “Charts” on page 21.

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RESERVOIR LAYERS Relative Permeability

Relative Permeability The use of Relative Permeabilities in multi‐phase flow is made by the Normalized Pseudo‐Pressure Calculation Model. The Relative Permeabilities are calculated for each Phase over a range of Flowing Pressures between Atmospheric and Layer Pressure. The In‐Situ Flow Rates (and, therefore, Phase Saturations and Relative Permeabilities) will vary with Flowing Pressure.

i

For the Black Oil Fluid system, alternative IPR Calculation Models are available for multi-phase flow (i.e. Vogel and Straight-Line options). In these cases, the Productivity Index (J), is computed at Layer Pressure using the Relative Permeabilities appropriate for the In-Situ Water-Cut and GOR. The Fetkovich, Back Pressure, Pressure-Squared (p2) and Tabulated IPR options do not use the Relative Permeabilities.

Relative Permeability data are used in the computation of the Productivity Index (J), in the IPR Layer Parameters entry mode. •

For a Reservoir above the Bubble‐Point, the Vogel and Straight‐Line IPR Models for an Oil Fluid Type use Kro(Sw) and Krw(Sw) from the Oil/Water Relative Permeability data to compute (J). For a Reservoir below Bubble‐Point, these Models use Kro(Sw, Sg) and Krw(Sw,Sg) from the Oil/Water and Oil/Gas Relative Permeability data.

i

Sw is determined from the In-Situ Water-Cut, and Sg from the In-Situ Gas Fractional Flow Rate, both at Pressure (p) = player

In the absence of Water or Free Gas, Kro(Sw, Sg) becomes the End‐Point Kro in the Oil/Water Relative Permeability data, and Krw(Sw,Sg) becomes zero.


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A single value of (J) is computed (at Layer Pressure) and is applied in the Vogel or Straight‐Line equation.

i •

If the Water-Cut or GOR is changed, (J) also will change.

The Normalized Pseudo‐Pressure IPR Calculation Model requires the Relative Permeabilities to be calculated for each flowing Phase, over a range of Pressures between Atmospheric and Layer Pressure. Therefore, (J) varies with flowing Pressure, even above Bubble‐Point — it does not have a single value.

The Relative Permeability data sets are used as follows, according to which Phases are flowing: 3‐Phase Flow: •

Black Oil system below the Bubble‐Point with a non‐zero Water‐Cut and GOR, or Condensate system below the Dew‐Point with non‐zero WGR and CGR: Relative Permeabilities (Kro, Krg, Krw), derived from Oil/Gas and Oil/Water tables at Sw, Sg (by Stoneʹs Method).

2‐Phase Flow:

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•

Black Oil system above the Bubble‐Point with a non‐zero Water‐Cut: Relative Permeabilities (Kro, Krw), calculated from the Oil/Water table at Sw.

•

Black Oil system below the Bubble‐Point with zero Water‐Cut: Relative Permeabilities (Kro, Krg), calculated from the Oil/Gas table at Sg.

•

Condensate above the Dew‐Point with non‐zero WGR: Relative Permeabilities (Krg, Krw), calculated from the Gas/Water table at Sw.

•

Condensate below the Dew‐Point with a zero WGR: Relative Permeabilities (Kro, Krg), calculated from the Oil/Gas table at Sg.

•

Dry Gas with a non‐zero WGR: Relative Permeabilities (Krg, Krw), calculated from the Gas/Water table at Sw.



Single‐Phase Flow: •

Black Oil above the Bubble‐Point with zero Water‐Cut: End Point Relative Permeability Kro (normally set to 1.0) taken from the Oil/Water table at Swi.

•

Gas with zero WGR or Condensate above the Dew‐Point with zero WGR: End Point Relative Permeability Krg (normally set to 1.0) from the Gas/Water table at Swi.

TO PLOT RELATIVE PERMEABILITY: 1 Open the Configuration menu in the Navigator. 2 Select Reservoir from the Model Navigator. The Reservoir Layers Data configuration screen is opened in the main content pane. 3 Open the Rel. Perm. tab (see Figure 3‐14).


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Figure 3-14: Relative Permeability

4 Select the Parametric Relative Permeability data formats if Parametric Relative Permeability data (Corey Coefficients5) are available. The End‐Point Relative Permeabilities and Saturations are specified together with the Curve Exponents so that actual Relative Permeabilities can be calculated at any Saturation. A Corey Coefficient of 1.0 gives a straight line; real curves are concave, with m and n > 1. 4a

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Enter values for the following parameters:



Gas/Water End‐Point Parameters: — Krg. The Gas End‐Point Relative Permeability at Irreducible Water Saturation (Swi). For a Gas Reservoir, this would conventionally be 1.0 if the effective Permeability at Irreducible Water Saturation has been entered. — Krw. The Water End‐Point Relative Permeability at Residual Gas Saturation (Sg). — Swi. The Irreducible Water Saturation. — Sgr. The Residual Gas Saturation. — m. The Corey Exponent for the Gas Relative Permeability Curve (typically a value of 3.5). — n. The Corey Exponent for the Water Relative Permeability Curve (typically a value of 2.0).

i

These parameters will create a plot of Krg and Krw (Y-axes) versus Water Saturation (Sw) in the WellFlo Graphing Window.


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Gas/Oil End‐Point Parameters (total pore volumes): — Kro. The Oil End‐Point Relative Permeability at Critical Gas Saturation (Sgc), (and Irreducible Water Saturation (Swi), as specified in the Oil/Water area below). — Krg. The Gas End‐Point Relative Permeability at Residual Oil Saturation (Sor), (and Irreducible Water Saturation (Swi), as specified in the Oil/Water area below). — Sgc. The Critical Gas Saturation into this field (i.e. fraction of Total Pore Volume). — Sorg. The Residual Oil Saturation into this field (i.e. fraction of Total Pore Volume). — m. The Corey Exponent for the Oil Relative Permeability Curve (i.e. typically a value of 1.7). — n. The Corey Exponent for the Gas Relative Permeability Curve (i.e. typically a value of 2.4).

i i

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Sgc + Sorg + Swi (Oil/Water Relative Permeabilities) < 1.0

These parameters will create a plot of Kro and Krg (Y-axes) versus Gas Saturation (Sg) in the WellFlo Graphing Window.



Oil/Water End‐Point Parameters: — Kro. The Oil End‐Point Relative Permeability at Irreducible Water Saturation (Swi). For an Oil Reservoir, this would conventionally be 1.0 if the effective Permeability at Irreducible Water Saturation has been entered. — Krw. The Water End‐Point Relative Permeability at Residual Oil Saturation (Sor). — Swi. The Irreducible Water Saturation. This saturation is also used for Gas/Oil. — Sor. The Residual Oil Saturation. — m. The Corey Exponent for the Oil Relative Permeability Curve (i.e. typically a value of 3.5). — n. The Corey Exponent for the Water Relative Permeability Curve (i.e. typically a value of 2.0).

i i

The "typical" values quoted for the exponents are averages based on the work of Tjolsen, Scheie and Damsleth6 for Oil/Water, and Honarpour, Koederitz and Harvey7 for Gas/Oil.

These parameters will create a plot of Kro and Krw (Y-axes) versus Water Saturation in the WellFlo Graphing Window.

4b

Select a parameter type from the drop‐down list at the top of the Relative Permeability screen to plot it in the Graphing Window.

4c

Click Plot.

The relative permeability is plotted in the chart at the right (see Figure 3‐15).


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Figure 3-15: Gas/Water End-Point Parameters Plot

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You can click the pin icon at the top right of the chart to unpin the plot and view or move it in a floating window (see Figure 3-16). This floating window remains in the foreground of your screen even when switching applications.


RESERVOIR LAYERS Relative Permeability Figure 3-16: Gas/Water End-Point Parameters Plot (unpinned)

i

Click the pin icon again to re-pin the plot to its original position.

5 Select the Tabular Relative Permeability data formats if Tabular Relative Permeability data are available.

i

At least two points (corresponding to the End-Point Relative Permeabilities and Saturations) must be entered and Saturation data must be entered in ascending order.

— For Gas Wells, only the Gas/Water table is required. — For Black Oil Wells, only the Gas/Oil and Oil/Water tables are required. — For Gas Condensate or Volatile Oil Wells, all three tables are required.


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5a

Add data to the permeability sections by first adding rows to the tables, and then selecting a unit type and entering values for the following parameters: — Water Saturation. Sw values between Swi (Irreducible Water Saturation, where Krw=0) and (1 ‐ Sor, where Kro=0) inclusive for an Oil/Water table, or (1 ‐ Sgr, where Krg=0) inclusive for a Gas/Water table. — Gas Saturation. Sg values between Sgc (Critical Gas Saturation, where Krg=0) and (1 ‐ Sorg ‐ Swi, where Kro=0) inclusive for an Oil/Gas table. The maximum Gas Saturation allowed is (1 ‐ Swi), where Swi is the first (Irreducible) Water Saturation in the Oil/Water table. — Water Relative Permeability. Values of Krw corresponding to the Water Saturation values. End‐Point values must be entered. — Oil Relative Permeability. Values of Kro corresponding to the Water or Gas Saturation values. End‐Point values must be entered. — Gas Relative Permeability. Values of Krg corresponding to the Water or Gas Saturation values. End‐Point values must be entered.

5b

Select a parameter type from the drop‐down list at the top of the Relative Permeability screen to plot it in the Graphing Window.

5c

Click Plot.

The relative permeability is plotted in the chart at the right. If the Gas/Water Table is selected, the plot will display Krg and Krw (Y‐axes) versus Water Saturation (Sw).

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If the Gas/Oil Table is selected, the plot will display Kro and Krg (Y‐axes) versus Gas Saturation (Sg).

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If the Oil/Water Table is selected, the plot will display Kro and Krw (Y‐axes) versus Water Saturation (Sw).


RESERVOIR LAYERS Skin Analysis

SKIN ANALYSIS This configuration screen is generated when Use calculated skin is checked in the General tab of the Reservoir Layers Data configuration screen. The versions of the configuration screen generated for Oil and Gas Wells differ only with respect to some of the units.

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The Skin tab is available only under Layer Parameters in the Reservoir Layers Data configuration screen.

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For Black Oil Fluids, the Total Darcy Skin (S) and optionally, the Total Rate‐Dependent Skin (D) can be calculated or input; (S) will be incorporated in the Semi‐Steady‐State Productivity Index (J), and (D) will be incorporated in the Non‐Darcy Flow Coefficient (F), to compute the Layer IPR.

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For Gas or Condensate Fluids, both the Total Darcy Skin (S) and the Total Rate‐Dependent Skin (D) components are computed or input by default; (S) will be incorporated in the Darcy Flow Coefficient (B), and (D) will be incorporated in the Non‐Darcy Flow Coefficient (F), to compute the Layer IPR.

Skin Analysis: Completion (Vertical) This screen is used to configure non‐fractured vertical wells.

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Depending on the choice of Open Hole or Cased Hole, and whether or not Gravel Pack was also selected, various fields will be grayed-out (i.e. disabled), when they are not applicable to the currently selected completion option.

TO CONFIGURE SKINS: 1 Open the Configuration menu in the Navigator. 2 Select Reservoir from the Model Navigator.


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RESERVOIR LAYERS Skin Analysis: Completion (Vertical)

The Reservoir Layers Data configuration screen is opened in the main content pane. 3 Open the Skin tab (under Layer Parameters) (see Figure 3‐17). Figure 3-17: Skin (Vertical)

4 Select an appropriate Completion Type from the drop‐down list.

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Depending on the choice of Open Hole or Cased Hole, and whether or not Gravel Pack was also selected, various fields will be grayed-out (i.e. disabled), when they are not applicable to the currently selected Completion option.


RESERVOIR LAYERS Skin Analysis: Completion (Vertical) 5 Fill in the remaining fields for the Completion Type selected: •

Damage Skin. Check to include a Damaged Zone in the Total Skin

Calculations. It will affect Damage Skin and Perforation Skin. If this checkbox is unchecked, no Damaged Zone exists. The Damage Permeability is set internally to be equal to the Effective Permeability of the Layer. This affects the calculation of the Damage Skin (‐> 0), Perforation + Damage Skin (‐> Perforation component only), and Gravel Pack Turbulent Skin.The effect of Formation Damage on Deliverability is calculated using the following data: — Damaged permeability. The Damaged Zone Permeability.

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To exclude Formation Damage effects, set Damage Permeability equal to the Rock Permeability or disable the Damage option.

— Dmg. Zone thickness. The Thickness of the Damaged Zone (measured from the Sand‐Face). — Damage skin. Displays the Skin contribution from the above data.

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The Vertical Permeability, which is entered in the Limited Entry Skin section, also is used in the Damage Skin computation.

Limited Entry Skin. Check to include the effect of Limited Entry in the Total

Skin Calculations. This is the Skin due to the length and position of the Open Interval within the formation (i.e. only applicable to the Vertical Well category13). The following data are required: — Nearest Meas. Formation Dist. The shortest Measured Distance from one end of the Open Interval (i.e. Open Hole or Perforated) to the Top or Bottom of the Layer. — Vertical permeability. The Vertical (i.e. Dip‐Normal) Permeability. — Open Interval (MD). For an Open Hole completion, enter the length of the Open Hole section. For a Cased Hole completion, enter the total length of Perforated Casing or Liner. These are measured lengths and should refer to the interval/s actually contributing to production,


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rather than the nominal Open Interval. The Interval Open to Flow (i.e. measured along the Well) is displayed alongside as a Percentage of the Layer Thickness (as also measured along the Well). The layer Thickness, entered in the Layer Parameters ‐ General tab, is a vertical thickness, while the Open Interval is measured along the Well and includes any Well Deviation. For example, if the layer Thickness is 100 ft. with the Angle of Deviation set to 0°, an Open Interval of 40 ft represents 40% of the total possible (100 ft). If the Angle of Deviation is subsequently changed to 60°, the Layer Thickness as measured along the Well becomes 200 ft (100 ÷ Cos 60), so the same 40 ft Open Interval now represents only 20% of the total possible. The combined effects of Partial Completion and Well Deviation are accounted for in the Total Skin Factor. — Limited Entry Skin. Displays the Skin contribution calculated from the above data. •

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Deviation Skin. Check to include a Deviation effect in the Total Skin Calculations. The Deviation Angle is used in the computation of Deviation Skin, Limited Entry Skin, and Total Skin. If this is unchecked, all effects of Well Deviation will be removed and all Skin Factors will be recalculated as if the Well were Vertical.



This is the Skin due to the Well Deviation relative to the Layer (i.e. only applicable in the Vertical Slant Well category12). The Skin computation is only recommended for Well Deviations less than 75°. In Anisotropic Reservoirs, this limit is higher and a warning prompt will be issued by WellFlo to warn users. Although computations up to 90° can still be performed, the Skin Analysis for a Horizontal Completion (see “Skin Analysis: Completion (Horizontal)” on page 175) should be considered as an alternative. — Well Deviation. The average Angle of Deviation of the Well across the Layer. For the purposes of Skin Analysis, this Angle is measured relative to Formation Dip‐Normal rather than the Vertical.

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The Deviation Angle is used in the Limited Entry and Total Skin computations. This Deviation Angle is not used in the Nodal Analysis. The Well Component Deviations are defined in “Use of Depths and Deviations” on page 47.

Gravel Pack: This is the Skin due to the addition of a Gravel Pack and will only be enabled if one of the Gravel Pack Completion options has been selected in the Completion Type drop‐down list. The same data are entered for both Internal (Cased completion) and External (Open Hole) Gravel Packs.

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In a Cased Completion, the Perforation Data also are used in the computation.

— Inner Radius. The Inner Radius of the Gravel Pack (i.e. Slotted Liner Outside Diameter (OD) ÷ 2). — Permeability. The average Gravel Permeability. — Efficiency. The efficiency of the Gravel Pack. This reflects any difference between theoretical and observed Gravel Pack Performance. Where the Calculated Skin = theoretical Skin ÷ Efficiency. The Pressure Drop across the Gravel Pack will double if the Efficiency = 0.5. This parameter provides a means of modeling the degradation of Gravel Permeability.


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For Cased Hole, Linear Flow is assumed along the Perforation Tunnel to the Screen. A correction is made, according to the contrast between the Gravel and Rock Permeability, to reflect the fact that while flow may be predominately to the Perforation Tip when kgp >> k, it will tend towards the Perforation Base for smaller values of kgp, or for decreasing Gravel Efficiency. This correction on smaller values of kgp, or for decreasing Gravel Efficiency (an Effective Perforation Length) was proposed by Pucknell and Mason14 and is applied to both Darcy and Non‐Darcy Gravel Pack Skin contributions. — Gravel Pack Skin: Displays the Skin contribution calculated from the above data. •

Perforation. This applies only to Cased Hole Completions and includes the combined effect of the Perforations and Formation Damage if a Damaged Zone has been defined. The following Perforation Data are required: — Perf. Diameter. The Diameter of the Perforation Entry Hole (in the Casing Wall). Crushed Zone. This section is used to enter the Skin attributed to the Crushed Zone around the Perforation Tunnel.

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This Skin may be negligible if Underbalanced Perforating has been used, owing to more efficient Clean-Up.

If a value is known (or is to be assumed), leave Use Calculated Skin unchecked and enter the value into the Measured Skin field.

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RESERVOIR LAYERS Calculations (Vertical) To compute a theoretical value, check Use Calculated Skin and enter values for the Crushed Zone Permeability (Kcz) — reckoned to be of the order of 10% of the Rock Permeability and Crushed Zone Thickness (Tcz). The computed value will be displayed in the Calculated skin field. — Shot Penetration. The Shot Penetration Length measured from the Sand Face (not the Casing Wall) to the tip of the Perforation Tunnel. — Shot Density. The Shot Density (i.e. Number of Shots per Unit Length). — Shot Phasing. The Shot Phasing Angle (i.e. Angle between the Perforation Tunnels projected onto a horizontal plane). — Flow Shape Factor. The Correlation8‐11 for the Darcy Flow Shape Factor. — Perforation skin. Displays the Skin contribution from the Perforations, including the Damaged Zone (if it has been defined). 6 Click Apply to save your changes.

Calculations (Vertical) For the Vertical Well category, the calculations take the following form: Total Darcy Skin (S): Figure 3-18: Total Darcy Skin (S)

where (as appropriate): Sd+p is the combined Perforation and Damaged Skin (Cased Hole) or the Damage Skin (Open Hole), Sgp is the Gravel Pack Skin, b is the Penetration Ratio (= measured Open Interval ÷ Layer Thickness as measured along Well). Sdev is the Deviation Skin, for 100% Penetration (b = 1).


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RESERVOIR LAYERS Calculations (Vertical)

PPSF is the Partial Penetration Scaling Factor15 Slim is the Limited Entry Skin, for zero Deviation. Total Non‐Darcy (D): Figure 3-19: Total Non-Darcy (D)

where (if appropriate): b is defined above, under Total Darcy Skin. Dd+p is the Non‐Darcy Completion Skin Component (Perforations and/or Damaged Zone) computed using an Inertial Coefficient16: Figure 3-20: Inertial Coefficient16

Dgp is the Non‐Darcy Gravel Pack Component Skin, computed using an Inertial Coefficient17: Figure 3-21: Inertial Coefficient17

Dgp is zero if there is no Gravel Pack.

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RESERVOIR LAYERS Skin Analysis: Completion (Horizontal)

Skin Analysis: Completion (Horizontal) The differences between the IPR calculations for Horizontal and Vertical Well completions are accounted for in the types of Darcy Skins (S) computed (i.e. Non‐Darcy Skin (D) calculations are identical in Vertical and Horizontal Wells), and the way they are combined in the total Skin terms: •

There is no Deviation Skin

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Limited Entry Skin is replaced by Convergence Skin

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Damage Skin, Perforation Skin and Gravel Pack Skin calculations are identical to those for a Vertical completion (refer to “Skin Analysis: Completion (Vertical)” on page 167 for details of these calculations), except where appropriate, calculations are performed using a Mean Effective Permeability (k) in the vertical plane and are modified to include the Vertical Permeability component (kv). Refer to the “Calculations (Horizontal)” on page 180 for more details.

TO CONFIGURE SKINS: 1 Open the Configuration menu in the Navigator. 2 Select Reservoir from the Model Navigator. The Reservoir Layers Data configuration screen is opened in the main content pane. 3 Open the Skin tab (under Layer Parameters) (see Figure 3‐22).


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Figure 3-22: Skin (Horizontal)

4 Select an appropriate Completion Type from the drop‐down list.

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Depending on the choice of Open Hole or Cased Hole, and whether or not Gravel Pack was also selected, various fields will be grayed-out (i.e. disabled), when they are not applicable to the currently selected Completion option.


RESERVOIR LAYERS Skin Analysis: Completion (Horizontal) 5 Fill in the remaining fields for the Completion Type selected: •

Damage Skin. Check this checkbox to include a Damaged Zone in the Total

Skin Calculations. It will affect Damage Skin and Perforation Skin. If this checkbox is unchecked, no Damaged Zone exists. The Damage Permeability is set internally to be equal to the Effective Permeability of the Layer. This affects the calculation of the Damage Skin (‐> 0), Perforation + Damage Skin (‐> Perforation component only), and Gravel Pack Turbulent Skin.The effect of Formation Damage on Deliverability is calculated using the following data: — Damaged permeability. The Damaged Zone Permeability.

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To exclude Formation Damage effects, set (ka) equal to the Rock Permeability or disable the Damage option.

— Dmg. Zone thickness. The Thickness of the Damaged Zone (measured from the Sand‐Face). — Damage skin. Displays the Skin contribution from the above data. •

Convergence Skin. This is the Skin due to Flow Convergence toward the

Wellbore in the vertical plane. It is a function of the Rock Vertical Permeability (kv) and the position of the Well between the Upper and Lower Layer Boundaries (Goode and Kuchuk18). The following data are required: — Nearest Meas. Formation Dist. The average Distance from the Well Axis (i.e. in the Producing Interval) to the Top or Bottom of the Layer, whichever is closer. — Vertical permeability. The Vertical (or Dip‐Normal) Permeability of the Rock at Irreducible Water Saturation (Swi). The Rock Anisotropy will be defined by the ratio of the specified Vertical and Effective Permeabilities (refer to the “Calculations (Horizontal)” on page 180 for more details about how these calculations are performed). •

Length Selection. This area is used to specify the Length (Lw) of the open Horizontal section of the Well. This is analogous to the Open Interval in a Vertical or Slant Well. There are two input options:


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— Design Length. The intended Open Interval Length (i.e. for Slotted Liner, Perforations or Open Hole). — Effective Length. The actual (i.e. Producing) Open Interval (best estimated from production logging or well testing). •

Perforation. This only applies to Cased Hole Completions and includes the combined effect of the Perforations and Formation Damage if a Damaged Zone has been defined. The following Perforation Data are required: — Perf. Diameter. The Diameter of the Perforation Entry Hole (in the Casing Wall). Crushed Zone. This section is used to enter the Skin attributed to the Crushed Zone around the Perforation Tunnel.

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This Skin may be negligible if Underbalanced Perforating has been used, owing to more efficient Clean-Up.

If a value is known (or is to be assumed), leave Use Calculated Skin unchecked and enter the value into the Measured Skin field.

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RESERVOIR LAYERS Skin Analysis: Completion (Horizontal) To compute a theoretical value, check Use Calculated Skin and enter values for the Crushed Zone Permeability (Kcz) — reckoned to be of the order of 10% of the Rock Permeability and Crushed Zone Thickness (Tcz). The computed value will be displayed in the Calculated skin field. — Shot Penetration. The Shot Penetration Length measured from the Sand Face (not the Casing Wall) to the tip of the Perforation Tunnel. — Shot Density. The Shot Density (i.e. Number of Shots per Unit Length). — Shot Phasing. The Shot Phasing Angle (i.e. Angle between the Perforation Tunnels projected onto a horizontal plane). — Flow Shape Factor. The Correlation8‐11 for the Darcy Flow Shape Factor. — Perforation skin. Displays the Skin contribution from the Perforations, including the Damaged Zone (if it has been defined). •

Gravel Pack: This is the Skin due to the addition of a Gravel Pack and will only be enabled if one of the Gravel Pack Completion options has been selected in the Completion Type drop‐down list. The same data are entered for both Internal (Cased Completion) and External (Open Hole) Gravel Packs.

i

In a Cased Completion, the Perforation Data also are used in the computation.

— Inner Radius. The Inner Radius of the Gravel Pack (i.e. Slotted Liner Outside Diameter (OD) ÷ 2). — Permeability. The average Gravel Permeability. — Efficiency. The efficiency of the Gravel Pack. This reflects any difference between theoretical and observed Gravel Pack Performance. Where the Calculated Skin = theoretical Skin ÷ Efficiency. The Pressure Drop across the Gravel Pack will double if the Efficiency = 0.5. This parameter provides a means of modeling the degradation of Gravel Permeability.


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RESERVOIR LAYERS Calculations (Horizontal)

For Cased Hole, Linear Flow is assumed along the Perforation Tunnel to the Screen. A correction is made, according to the contrast between the Gravel and Rock Permeability, to reflect the fact that while flow may be predominately to the Perforation Tip when kgp >> k, it will tend towards the Perforation Base for smaller values of kgp, or for decreasing Gravel Efficiency. This correction on smaller values of kgp, or for decreasing Gravel Efficiency (an Effective Perforation Length) was proposed by Pucknell and Mason14 and is applied to both Darcy and Non‐Darcy Gravel Pack Skin contributions. — Gravel Pack Skin: Displays the Skin contribution calculated from the above data. 6 Click Apply to save your changes.

Calculations (Horizontal) The following details apply to the Pseudo‐Linear and Pseudo‐Radial Inflow Models (i.e. described in the Radial Drainage Area Shape configuration screen. See “Configuring Drainage Geometry” on page 140). The Joshi Model for Steady‐State Inflow defines some of the component Skins differently and only the mechanical Skin components are displayed in the Skin Analyzer when this model is selected. Calculations are performed using a Mean Effective Permeability (k) in the vertical plane and are modified to include the Vertical Permeability component (Kiev): •

Users enter a Damaged Zone Permeability (a) in the Damage Skin section of this screen, which is taken as the damaged equivalent of keff, the (Horizontal) Effective Layer Permeability to the hydrocarbon phase at Irreducible Water Saturation (Swi). It is normally assumed to be the same in the x‐ and y‐directions, but in the event of areal anisotropy, use:

Figure 3-23: Areal Anisotropy

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The Vertical (or Dip‐Normal) Permeability (kv), of the Reservoir Layer at Irreducible Water Saturation (Swi), is entered in the Convergence Skin section of the screen.

•

WellFlo then calculates the Reservoir Anisotropy (A) from:


RESERVOIR LAYERS Calculations (Horizontal) Figure 3-24: Calculating Reservoir Anisotropy

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WellFlo calculates the Damaged Zone Vertical Permeability (kva) from ka x A

•

Using ka and kva, WellFlo computes the Average Vertical Radial Permeability (k) and uses this in the Damage Skin Equation:

Figure 3-25: Damage Skin Equation

For a Horizontal Well, the total Darcy Skin calculations take the following forms: Total Darcy Skin (S) for Pseudo‐Radial Inflow Model (excluding Joshi Model): Figure 3-26: Total Darcy Skin (S) for Pseudo-Radial Inflow Model

where: Scnv is the Convergence Skin from full Layer Thickness into the Wellbore Sp+d is the Perforation + Damaged Skin (Cased Hole) or Damaged Skin (Open Hole) Sgp is the Gravel Pack Skin Lw is the Effective Length or Design Length of the Producing Interval A is the Vertical Anisotropy Coefficient given by:


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RESERVOIR LAYERS Calculations (Horizontal)

Figure 3-27: Anisotrophy

h is the true Layer (i.e. Net) Thickness (measured Dip‐Normal) The term containing 4.4817 is an Effective Wellbore Radius term representing the beneficial effect of an extended open Horizontal Interval (after Goode and Wilkinson19 and Goode and Kuchuk18). Total Darcy Skin (S) for Joshi Steady‐State Inflow Model: Figure 3-28: Total Darcy Skin (S) for Joshi Steady-State Inflow Model

Total Darcy Skin (S) for Pseudo‐Linear Inflow Model: Figure 3-29: Total Darcy Skin (S) for Pseudo-Linear Inflow Model

where the terms are as defined above for Pseudo‐Radial Inflow, and Slfc is the Areal Flow Convergence Pseudo‐Skin defined by Goode and Thambynayagam20. L1 is the Length of the Rectangular Reservoir in the direction of the Well (refer to “Configuring Drainage Geometry” on page 140). Total Non‐Darcy Skin (D) for the Pseudo‐Radial Inflow Model (including Joshi Model): Figure 3-30: Total Non-Darcy Skin (S) for Pseudo-Radial Inflow Model

where A is the Vertical Anisotropy Coefficient:

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RESERVOIR LAYERS Skin Analysis: Completion (Fractured) Figure 3-31: Vertical Anisotropy Coefficient

Dp+d is the Perforation + Damage (Cased Hole) or Damage (Open Hole) Non‐Darcy Skin Coefficient, Dgp is the Gravel Pack Non‐Darcy Skin Coefficient. Total Non‐Darcy Skin (D) for the Pseudo‐Linear Inflow Model: Figure 3-32: Total Non-Darcy Skin for Pseudo-Linear Inflow Model

Skin Analysis: Completion (Fractured) This screen is used to configure fractured horizontal or vertical wells.

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Depending on the choice of Fractured Completion option, various fields will be grayed-out (i.e. disabled) when they are not applicable to the currently selected Fractured Completion option.

This screen (with or without Gravel Pack) is basically the same for Vertical and Horizontal Well types, and they have many of the component Skin options in common. The versions of the dialog generated for Oil and Gas Wells differ only with respect to some of the Units. The various component Skin Effects contributing to the total Skin are listed in the Contributory Effects area. Each contribution can be enabled or disabled for inclusion or exclusion from the Calculated Total Skin Factors.

TO CONFIGURE SKINS: 1 Open the Configuration menu in the Navigator. 2 Select Reservoir from the Model Navigator.


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RESERVOIR LAYERS Skin Analysis: Completion (Fractured)

The Reservoir Layers Data configuration screen is opened in the main content pane. 3 Click Use calculated skin. 4 Click Fractured. 5 Open the Skin tab (under Layer Parameters) (see Figure 3‐33). Figure 3-33: Skin (Fractured)

6 Select a Fracture Type.

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RESERVOIR LAYERS Skin Analysis: Completion (Fractured) 7 Check the required Contributory effects to be included into the total Skin calculations. As each option is selected, an associated set of specific input parameters will appear in the area to the right of the list field; these are described as follows: •

Proppant Darcy Properties: The parameters in this section are used to compute the effect of the resistance to Darcy Flow along the Fracture caused by the Finite Conductivity of the Proppant material (Wilkinson21). The effect of Fracture Connection on Non‐Darcy Flow is also computed. This is determined by how much of the Fracture actually intersects the Wellbore (e.g. in the extreme case of a Horizontal Well and a Vertical Fracture, very little of the Fractured Interval Height will actually intersect and there will be a strong Flow Convergence into the Well).

The first two entry fields are linked by the formula: Figure 3-34: Proppant Darcy Properties Formula

entering one parameter will automatically update the other: — Proppant permeability. Enter a value for the Permeability of the Proppant. — Dimensionless fracture conductivity. Enter the Dimensionless Conductivity of the Fracture. — Use finite conductivity skin. If this checkbox is checked, the Proppant Finite Conductivity effects will be included into the total Skin calculations. The Finite Conductivity Skin is displayed in the underlying field. — Use fracture connection skin. If this checkbox is checked, the Fracture Connection effects will be included into the total Skin calculations. The Fracture Connection Skin is displayed in the underlying field.

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The Fracture Connection Skin is determined by the Intersection Angle entry in the Fracture Dimensions section.


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•

Proppant Non-Darcy properties. The parameters in this area are used to compute the effect of the Inertial Resistance to flow along the Fracture caused by the Finite Conductivity of the Proppant material (i.e. Non‐Darcy Skin). The effect of Fracture Connection on Non‐Darcy Flow is also computed. This is determined by how much of the Fracture actually intersects the Wellbore (e.g. in the extreme case of a Horizontal Well and a Vertical Fracture, very little of the Fractured Interval Height will actually intersect and there will be a strong Flow Convergence into the Well). The Non‐Darcy Skin Coefficient (D), for a Finite Conductivity Fracture depends on the Inertial Resistance (bp) of the Proppant.

— Enter the Constant term and Exponent term in the relevant fields. — Alternatively, check Use calculated inertial resistance coeff. and a value for the Measured inertial resistance coeff. to compute the Non‐Darcy Finite Conductivity Skin Coefficient (D). Figure 3-35: Non-Darcy Skin Coefficient

The Non‐Darcy Finite Conductivity Skin Coefficient (D) will also be calculated simultaneously, where: (kp) is the Proppant Permeability, entered under the Proppant Darcy Properties section.

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Typical values for a 16/20 Proppant are: C = 6.75E+10, n = 1.02 (Walsh and Leung22).



•

Fracture face damage: This is used to model the effects of Permeability Reduction over the face of the Fracture caused by Fluid Loss Damage. It also can model any improvements in permeability. — Damaged permeability. Enter the Permeability of the Fracture Face Damaged Zone. — Damaged thickness. Enter the thickness of the Fracture Face Damaged Zone. — Use calculated fracture face skin. Use this checkbox to control whether the calculated Fracture Face Skin (Sf) or the measured Fracture Face Skin (Sf) is used. — Measured fracture face skin. If Use calculated fracture face skin is unchecked, enter a measured value for the Fracture Face Skin if the data for performing a calculation is unavailable.

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Choked fracture: This allows for the choking effect of a reduction in Fracture Width and/or Proppant Permeability at the mouth of the Fracture (e.g. change of Proppant Sizing). — Choked half-length. Enter the length of the Choked Region along one Fracture Wing. — Choked width. Enter the width of the Choked Region. — Choked permeability. Enter the Permeability of the Proppant (or other material) in the Choked Region. — Choked Darcy Skin and Choked Non-Darcy Skin. These fields will display the Choked Fracture Darcy and Non‐Darcy Skin calculated from the parameters entered above.

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For the Non-Darcy Coefficient, the Inertial Resistance of the Choked Region is computed from the Choked Region Permeability using the same C and n values as the Proppant (i.e. entered under the Contributory Effect section for Proppant Non-Darcy Properties).

Limited Height: This option models the convergence of Darcy Flow from full Layer Thickness into a Fracture of Limited Height. The Fracture Height is specified as Fractured Interval (hf), in the Fracture Dimensions section.


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The Layer Thickness is specified in the Layer Parameters configuration screen. For consistency, both are true (or Dip‐Normal) Heights. — Vertical permeability. Enter a value for the Vertical Permeability of the Layer. — Limited entry skin. This field will display the Limited Height Darcy Skin calculated from the parameter entered above. •

Frac and Pack. This option is available only when Frac‐and‐Pack has been selected as a Fracture Type. It models Darcy and Turbulent flow through a combined Gravel Pack and Propped Fracture, and includes convergence to the Perforations in a Cased Completion.

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The Gravel Pack parameters are the same as for the external and internal Gravel Packs described in “Skin Analysis: Completion (Vertical)” and “Skin Analysis: Completion (Horizontal)”.

— Pack inner radius. Enter the Inner Radius of the Gravel Pack (i.e. half the Outside Diameter (OD) of the Slotted Liner) into this field. — Gravel permeability. Enter the Gravel Permeability into this field. — Gravel efficiency. Enter the Efficiency of the Gravel Pack into this field. This reflects any difference between theoretical and observed Gravel Pack Performance: calculated Skin = theoretical Skin / Efficiency. — Perforation diameter. Enter the Diameter of the Perforation Entry Hole into this field. — Effective shot density. Enter the Effective Shot Density into this field. This refers to the Number of Perforations per Foot (or Meter) that are actually connected to the two Fracture Wings. It may be less than the Gun Shot Density and will depend on the Shot Phasing and Geometry of the Fracture Propagation. •

Fracture Dimensions: The Fracture Plane is assumed to be Vertical, and the Fracture consists of two equal Wings propagated in opposite directions: — Fractured interval. The Vertical Height of the Fracture in the Reservoir (i.e. not at the Wellbore).

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RESERVOIR LAYERS Calculations (Fractured) — Fracture width. The (average) Width of the Fracture (i.e. perpendicular to the Fracture Plane). — Fracture half-length. The Length of one Wing of the Fracture (i.e. perpendicular to the Fracture Plane). — Intersection angle. The average deviation of the Well from Vertical over the Fractured Interval. This angle determines how much of the Fracture intersects with the Wellbore.

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In the extreme case of a Horizontal Well (a = 90°, Transverse Fracture), very little of the Fracture Height will actually intersect the Well, especially if the Fracture has propagated perpendicular to the Well.

The Intersection Angle should be measured from the projection of the Well Trajectory onto a vertical plane perpendicular to the Fracture. It may be less than the true deviation from the drilling survey (e.g. if the Well Trajectory is along the Fracture Plane, the Intersection Angle is zero; if it is perpendicular to the Fracture Plane, the Intersection Angle is equal to the Well Deviation).

Calculations (Fractured) The Total Darcy Skin (non‐turbulent flow) and Total Non‐Darcy Skin (turbulent flow) displayed include all the Contributory Effects that have been selected. Total Darcy Skin (S) is the sum of all the selected Darcy Skin components: Figure 3-36: Total Darcy Skin (S)

Total Non‐Darcy Skin Coefficient (D) is the sum of all the selected Non‐Darcy Skin components: Figure 3-37: Total Non-Darcy Skin Coefficient (D)


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RESERVOIR LAYERS References

REFERENCES 1 Goode, P.A. and Weakliness, D.J.: ʺInflow performance of Partially Open Horizontal Wellsʺ, JPT, (August 1991), pp. 983‐987. Also available as SPE 19341, presented at the SPE Eastern Regional Meeting, Morgantown, West Virginia, 24‐27 October (1989). 2 Goode, P.A. and Wilkinson, D.J.: SPE 23546, Supplement to SPE 19341, ʺInflow Performance of a Partially Open Horizontal Wellʺ, 1991. 3 Joshi, S.D.: ʺAugmentation of Well Productivity with Slant and Horizontal Wellsʺ, JPT, (June 1988), pp. 729‐739. Also available as SPE 15375, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, 5‐8 October (1986). 4 Yaxley, L.M.: ʺ New Stabilized Inflow Equations for Rectangular and Wedge‐Shaped Systemsʺ, SPE 17082, 1987. 5 Corey, A.T.: ʺThe Interrelation Between Gas and Oil Relative Permeabilitiesʺ, Prod. Mon. 19, 38, 1954. 6 Tjolsen, C.B.; Scheie, A. and Damsleth, E.: ʺA Study of the Correlation between Relative Permeability, Air Permeability and Depositional Environment on the Core‐Plug Scaleʺ, paper presented at the Second European Core Analysis Symposium, London, May 1991. Published in Advances in Core Evaluation II, Reservoir Appraisal, P.F. Worthington and D. Longeron (eds.), Gordon and Breach, London (1991), 169‐183. 7 Honarpour, M.; Koederitz, L. and Harvey, A.H.: ʺRelative Permeability of Petroleum Reservoirsʺ, CRC Press Inc., Boca Raton, Florida, (1986). 8 Locke, S.: ʺAn Advanced Method For Predicting the Productivity Ratio of a Perforated Wellʺ, JPT, December 1981 and SPE 8804 , presented at the Fourth Symposium on Formation Damage Control of the Society of Petroleum Engineers of AIME, held in Bakersfield, California, January 28‐29, 1980. 9 Egan: MSc Thesis, University College, Cork (1984), 10 Tariq S.M. and Karakas, M.: ʺSemi‐Analytical Productivity Models for Perforated Completionsʺ, SPEPE February 1991 and SPE 18247.

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11 Muskat, M. and McDowell, J.M.: ʺThe Effect on Well Productivity of Formation Penetration Beyond Perforated Casingʺ, Trans. AIME (1950) 189 pp. 309‐312. 12 Cinco, H; Miller, F.G. and Ramey Jnr., H.J.: ʺUnsteady‐State Pressure Distribution Created By a Directionally Drilled Wellʺ, SPE 5131, October 1974. 13 Streltsova‐Adams, T.D.: ʺPressure Drawdown in a Well With Limited Flow Entryʺ, SPE 7486, October 1978. 14 Pucknell, J.K. and Mason, J.N.E.: ʺPredicting the Pressure Drop in a Cased‐Hole Gravel Pack Completionʺ, SPE 24984, prepared for presentation at the European Petroleum Conference held in Cannes, France 16‐18, November 1992. 15 Burton R. and Parker C.: Dubai Petroleum Company Acidizing Manual, 1989. 16 MacLeod Jr., O.H.: ʺThe Effects of Perforating Conditions on Well Performanceʺ, JPT, January 1983, pp. 31‐39. 17 From experimental data, Pet. Eng. Dept., Heriot‐Watt University. 18 Kuchuk, F.J., Goode, P.A., et al : ʺPressure Transient Analysis and Inflow Performance for Horizontal Wellsʺ, SPE 18300, presented at the SPE 63rd. Annual Tech. Conf., Houston, Texas, USA, Oct. 2‐5, 1988. 19 Goode, P.A. and Wilkinson, D.J.: ʺInflow performance of Partially Open Horizontal Wellsʺ, JPT, (August 1991), pp. 983‐987. Also available as SPE 19341, presented at the SPE Eastern Regional Meeting, Morgantown, West Virginia, USA, Oct. 24‐27, 1989. 20 Goode, P.A. and Thambynayagam, R.K.M.: ʺPressure Drawdown and Buildup Analysis for Horizontal Wells in Anistotropic Mediaʺ, SPE Formation Evaluation, pp. 683‐697, December 1987. 21 Wilkinson, D.J.: ʺNew Results for Pressure Transient Behavior of Hydraulically Fractured Wellsʺ, SPE 18950, prepared for presentation at the SPE Joint Rocky Mountain Regional/Low Permeability Reservoirs Symposium and Exhibition held in Denver, Colorado, March 6‐8, 1989. 22 Walsh, D.M. and Leung, K.H.: ʺPost‐Fracturing Gas Well Test. Analysis Using Buildup Type Curves,ʺ SPEFE, September 1991, pp. 393‐400. Also available as paper SPE 19253.


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Chapter 4 TEMPERATURE MODEL This chapter explains how to configure a Temperature Model in WellFlo. Temperature Model ....................................................................... 194 Calculation Methods ................................................................. 194 Configuring a Temperature Model ......................................... 197 References ....................................................................................... 206


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TEMPERATURE MODEL Temperature Model

TEMPERATURE MODEL There are four models used in WellFlo for Temperature calculation.

Calculation Methods •

Manual. This is a very simple model, consisting of a fixed temperature at

each node in the system. For Tubular components with a finite length, the temperature at the upstream end (i.e. bottom end in a Producer) is specified. The temperature is interpolated linearly between this node and the temperature at the next node. This model can be used to impose a fixed temperature profile on the system; but obviously, this will be valid only at the Flow Rate at which the profile was derived or measured. •

Calculated. This is based on Rameyʹs1 and Willhiteʹs2 Heat Loss

correlations. The pressure effects are not modeled. Rameyʹs exponential Temperature Loss Model is used on a component‐by‐component basis, taking account of the deviation, which affects the external Temperature Gradient. A constant Geothermal Gradient is calculated from the Layer Temperatures and Surface Temperatures over the TVD of the reservoir. The exponential constant, or Relaxation Distance (A), for a given flow rate is calculated per component from its Heat Transfer Coefficient (Uwb), the Specific Heat of the wellbore fluid mixture (Cpf), and the Thermal Conductivity (Ke) of the surrounding Earth, Water or Air. Figure 4-1: Heat Transfer Coefficient

where, qm is the mass Flow Rate, and Ut is the total Heat Transfer Coefficient, given by:

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TEMPERATURE MODEL Calculation Methods

Figure 4-2: Relaxation Distance

rci is the inner Pipe Diameter. Uwb is the Heat Transfer Coefficient appearing in the component dialog, and includes Tubing, Annulus Fluid, Casing and Cement (i.e. Well components), or Pipeline and Insulating Jacket (i.e. Surface components). fD(t) is a dimensionless Transient Heat Conduction time function for the Earth, derived from the Hasan and Kabir3, 4 approximation to the finite Wellbore Radius solution of Carslaw and Jaeger5. When performing non‐sensitized calculations, the Transient Heat Conduction time function assumes a stable Production Time at default settings of 200 hrs for the Coupled Model and 100hrs for the Calculated Model. For Sensitivity calculations, other times may be entered in the Nodal Analysis Sensitivities configuration screen when Pressure and Temperature are selected as a Sensitivity Group and Elapsed Production Time is selected as a Group Variable (see “Creating and Editing Sensitivities” on page 218). The model changes at the Wellhead node. Instead of a varying External (Earth) Temperature (Te), there is assumed to be a constant Ambient Surface Temperature for each component. The Overall Heat Transfer Coefficient (Ut), is still used to find the Relaxation Distance, but the Ramey model is simplified and becomes independent of Depth, Elevation and Angle. Where a Surface component (or part of it), is below MSL, the external medium is assumed to be Water (i.e. equivalent default Heat Transfer Coefficient with free and forced convection of 3500 BTU/ft2.D.°F). Where the Surface component (or part of it), is above MSL, the external medium is assumed to be Air (i.e. equivalent default Heat Transfer Coefficient with free and forced convection of 100 BTU/ft2.D.°F). An option to (partially) bury the Surface component is also available.


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TEMPERATURE MODEL Calculation Methods

The Thermal Conductivities of Earth, Cement, Liquid, Gas, Steel, and Insulation can be customized in the Model Constants section of the Application Options dialog box, under Settings > Options... (see “Configuring Preferences” on page 18). The Heat Transfer Coefficients for free and forced convection in Air or Water can be specified under the Flowline tab in the Temperature Model configuration screen. There is also an option to specify the Thermal Properties of each Surface component and its Surrounding Medium, instead of using global values. •

Coupled Pressure‐Temperature Model6. This solves the Pressure Equation

(i.e. conservation of momentum) and the Energy Equation6 simultaneously, thereby taking into account the effects of Changing Pressure, including the Joule‐Thomson effect, on the moving fluid column. The Joule‐Thomson effect s also modeled at: — The Sandface Fluid Entry Point — The active Gas‐Lift Valve — Downhole Restrictions — The surface Choke

i •

Variations in Phase Properties with pressure and temperature are included for this model, which allows the Heat Transfer Coefficient due to internal convection7 to be calculated. In WellFlo, this is obtained from a correlation of the Nusselt Number7 for smooth pipes, which is based on the Reynolds Number, Prandtl Number and Moody Friction Factor of the produced fluid. The Thermal Conductivity of the produced fluid and the Hydraulic Diameter of the flow also are required. This calculation is performed for Tubular, Annular and Combined well flow types and Casing, Tubing, Flow Line and Riser/ Downcomers.

Calibrated. This is the same as the Calculated model, except that the above

Heat Transfer Calculations are calibrated against measured temperatures. The Ramey model is used in the wellbore and the simplified version of it is used beyond the Xmas Tree/Wellhead. However, the Relaxation Distances are calibrated so that the computed Xmas Tree/Wellhead temperatures and Separator Temperatures match values that are specified at a particular flow rate.

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TEMPERATURE MODEL Configuring a Temperature Model

The well (downhole) Relaxation Distances are calibrated against the Wellhead Flowing Temperature (i.e. not the Surface Temperature). The Surface facilities Relaxation Distances are then calibrated against the Temperature Loss from Xmas Tree/Wellhead to separator, again at the measured flow rate. At other flow rates, the temperatures will be calculated using the calibrated scalers on the Relaxation Distances. This model therefore should be the most accurate, when test data are available for reference.

Configuring a Temperature Model TO CONFIGURE A TEMPERATURE MODEL: 1 Open the Configuration menu in the Navigator. 2 Select Temperature Model from the Model Navigator. The Temperature Model configuration screen is opened in the main content pane (see Figure 4‐3).


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Figure 4-3: Temperature Model

3 Select a Model:

Manual 3a

Select Manual to use a set of user‐defined temperatures. Functionally, this is the simplest Temperature Model; it uses the temperatures specified by component and interpolates between them (e.g. the temperature used half‐way along a length of tubing is half‐way between the temperature at its lower end (i.e. the value entered for that tubing node) and its upper end (i.e. the value entered for the next node up the well). This is a static temperature description; the same profile will be used for any flow rate, and would normally depend on users having measured temperatures available. Insert new rows into the table under the Wellbore tab, as necessary, and enter values for the Measured Depth and Temperature. Insert new rows into the table under the Flowline tab, as necessary, and enter values for the Total Distance and Temperature.

198



Calculated 3b

Select Calculated to calculate the Temperature Profile at each flow rate from a component‐by‐component simplistic Heat Loss Model1,2.

Fluid is assumed to enter the wellbore at Layer Temperature and Heat Transfer is modeled between the moving Wellbore Fluid Column and the external Geothermal Temperature, accounting for the Heat Loss Coefficients of the intervening media. The well components lose heat by conduction from the Producing Fluid Temperature to the surrounding formation at a Geothermal Temperature interpolated between the Layer and Surface. The Heat Transfer depends on the Flow Rate, the fluid in the Annulus and the calculated or manually‐entered Heat Loss Coefficient of each component Downstream of the wellhead, Heat Transfer is modeled between the moving Flow Line Fluid and external Ambient Temperature. This is assumed to be constant at Air or Water standard heat transfer coefficients, or at the values specified in the Advanced Heat Loss Modeling section of each component (if used), depending on whether it is above or below MSL, and accounting for the Heat Loss Coefficients of the intervening media (e.g. Steel, Insulation). The surface components lose heat by convection from the Producing Fluid Temperature to the surrounding medium at the specified Atmosphere or Seawater temperature (depending on Elevation from MSL). The Heat Transfer in this case depends on the low Rate, the calculated or manually‐entered Heat Loss Coefficient of each component and the Heat Transfer Coefficient of the medium. The Calculated input screen is displayed in Figure 4‐4.


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Figure 4-4: Temperature Model - Calculated

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3c

Select Geothermal gradient or Surface temperature from the under the Wellbore tab and enter a value for the selected temperature.

3d

Check Gas in annulus if the Annulus is wholly or partly filled with gas. If this checkbox is not checked, the program assumes that all the annulus below the wellhead is filled with liquid.

3e

Check Gas to MD to define a Measured Depth (MD) for gas in the annulus. When Gas in annulus is checked, and this checkbox is not checked, WellFlo assumes that all the Annulus below the Wellhead is filled with Gas. This checkbox should be checked if the Annulus is only partly‐filled with Gas, and users can then enter the Measured Depth (MD) below which it is filled with Liquid.



WellFlo will use different Heat Loss Models for well components above and below the specified Measured Depth (MD). The Measured Depth (MD) should correspond to a Node Depth. If users enter a Measured Depth (MD) that lies within a component, WellFlo will either change the Heat Loss Model at the top or bottom of the component, depending on which is nearer.

i 3f

The Annulus Fluid Type can be either gas or not gas (i.e. liquid). The default Thermal Conductivity for gas = 0.504 BTU/ft.D.°F, and for Water = 9.192 BTU/ft.D.°F. These values can be modified in the Application Options dialog box (Settings > Options...), by entering appropriate Value Data conductivity values for the therm-cond-gas and/or therm-cond-liquid Value Names.

Insert new rows into the table under the Wellbore tab, as necessary, and fill in the following table data: — MD. The Measured Depth for each wellbore segment. — Calculated. Indicates whether the Heat Transfer Coefficient is calculated or manually input for each segment. Check Calculated to allow WellFlo to calculate it automatically, or uncheck Calculated to enter a value. — U. The heat transfer coefficient for each segment.

3g

Open the Flowline tab, and enter values for the Air and Water Standard heat transfer coefficients.

3h

Insert new rows into the table under the Flowline tab, as necessary, and fill in the following table data: — Distance from WH. The distance from the Wellhead. — Medium. Select Air or Water. — Burial Depth. If the flowline is partially buried, enter the depth from the surface to which it is buried. The Heat Loss, based on the fully‐exposed Heat Transfer Coefficient, will then be reduced by the buried portion of the pipe circumference, and a correction (usually a very small one) made for the additional warmed surface next to the flowline.


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Flowlines above MSL can be modeled as completely in air (i.e. enter a value = 0), partially buried (enter a value greater than 0), or buried. For the Heat Loss calculation, soil is given a default Thermal Conductivity of 7 BTU/ft.D°F. It can be customized via an entry in the Application Options dialog box (Settings > Options...). See “Configuring Preferences” on page 18 for more information. — Loss Model. Select Standard or Advanced. •

Standard. Global values are used for the thermal properties of the components and their surrounding media (as described under Heat Transfer Coefficient).

•

Advanced. Thermal properties can be specified for each individual component and its surrounding medium.

If the Advanced model is selected and no values for local heat loss variables have been entered yet, enter the required data in the table. The values entered will be used by this component only, and will override any conductivities set in the Application Options dialog box (Settings > Options...) and/or air and water Heat Transfer Coefficients set in other configuration screens. The value of the external convective Heat Transfer Coefficient will depend on the inclination angle of the node (i.e. different values will be obtained for Risers, Downcomers and Flowlines, since separate Heat Transfer Coefficients are used for vertical and horizontal inclined cylinders). The Heat Transfer Coefficient of an inclined node is obtained by interpolating between the horizontal and vertical values using the specified angle of inclination from vertical for the node. — Heat Transfer Coefficient. Enter a heat transfer coefficient for the fully‐exposed Flowline. The Heat Transfer Coefficient displayed takes into account the transfer of heat through the pipe wall and insulation. It assumes the following default thermal conductivities (in BTU/ft.D°F): •

Steel: 480

•

Insulation: 1.0

These values can be customised via entries in the Application Options dialog box (Settings > Options...). These global values will be used for all surface components if the Standard Heat Loss Model has been selected.

202



The Heat Loss to the medium surrounding the Flowline — water (subsea) or air/soil (surface) — is modeled at run time if the Calculated, Calibrated or Coupled Temperature Model is selected, using the following default heat transfer coefficients (in BTU/ft2.D°F): •

Surroundings (water, free and forced convection): 3500

•

Surroundings (air, free and forced convection): 100

These global values will be used throughout the surface system if the Standard Heat Loss model has been selected. — Insulation Thickness. Enter the thickness of the insulation surrounding the Flowline. If the Flowline is not insulated, then enter a value of 0 (used to calculate the Heat Transfer Coefficient if required). — Medium Temperature. The value for the air or water temperature. — Tide/Wind Speed. The value of the average wind or water speed. — Steel Conductivity. Thermal conductivity in oilfield units, default 480.0 d‐ft‐degF (users are allowed a range between 48 ‐ 4800 d‐ft‐degF). — Insulation Conductivity. Thermal conductivity in oilfield units, default 1.0 d‐ft‐degF (users are allowed a range between 0.01 ‐ 100 d‐ft‐degF).

i

Steel refers to the component material between the Inside Diameter (ID)and Outside Diameter (OD), and Insulation refers to the material between the Outside Diameter (OD) of the component and the Insulation Diameter surrounding the component (e.g. the value entered for Steel can represent manufacturer’s data for a multi-layered line).


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Coupled 3i

Select Coupled3,4 to calculate the Temperature Profile incrementally, based on the data used by the Calculated model, but also including variations in Phase Properties with pressure and temperature, the Gravitational, Kinetic, and Joule‐Thomson effects, Internal Convection in the wellbore fluids, and Forced Convection caused by movement of the external medium (where seawater or air are involved).

i

Refer above to the Calculated model description for comments on Geothermal Gradient, and the medium surrounding the Flow Line. The sub-surface model will assume Liquid in the Tubing-Casing Annulus unless the Gas in annulus checkbox option is checked.

This model solves calculations simultaneously for pressure and temperature at each step; as it models heat loss rigorously, it is the recommended option. However, for Top‐Down calculations, the Solution Node Temperature (e.g. Casing) is very sensitive to the Start Node Temperature (e.g. Wellhead), and users should be prepared to make small adjustments to the Start Node Temperature if the computed Temperature Profile appears unreasonable. This problem does not arise in Bottom‐Up mode, because in this direction the Solution Node (e.g. Wellhead) temperature will be relatively insensitive to Start Node Temperature (e.g. Reservoir). 3j

Relaxation Distance Factor. Enter a multiplier to the Relaxation

Distance calculated by the Coupled Temperature Model to perform manual Tuning on the Temperature Profile produced by the Coupled Temperature Model.

i 204

The Relaxation Distance Factor is a multiplier (default 1.0) that scales the computed Ramey1 Relaxation Distances, and can be used to calibrate against measured temperatures.



Calibrated 3k

Select Calibrated to tune the calculated model to temperatures measured at a known flow rate at the wellhead (or gauge) and at the Outlet Node (e.g. Separator). The calibration applies one Tuning Factor from the Reservoir to the Wellhead (or Gauge), and another Tuning Factor from the Wellhead (or Gauge) to the Outlet Node, such that the calculated temperatures at the specified Flow Rate match the specified Wellhead (or T Gauge) temperature and Outlet Node temperature. These Tuning Factors are then applied to the calculated temperature model at each of the flow rates specified for Nodal Analysis.

3l

Enter values for the following fields: — Flow Rate. The Flow Rate (for the appropriate fluid phase) at which the Wellhead (or Gauge) and Outlet Node temperatures were measured. In the case of oil wells, this is the total Liquid Rate, with the water‐cut assumed to be the same as that specified in the Oil Fluid Parameters configuration screen.

i i

Refer above to the Calculated model description for comments on Geothermal Gradient, and the medium surrounding the Flowline. The sub-surface model will assume Liquid in the Tubing-Casing Annulus unless the Gas in annulus checkbox option is checked. Fluid is assumed to enter the Wellbore at Layer Temperature.

The Calibration is performed at the Base Case/s of Fluid Ratios that were entered in the relevant Fluid Parameters configuration screen, even when these Fluid Ratios are Sensitivities.

— Wellhead Temp. The Wellhead (or Gauge) temperature. — Outlet Temp. The temperature of fluid entering the separator or at the end of the Flowline. 4 Click Apply to save your changes.


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4

4

TEMPERATURE MODEL References

REFERENCES 1 Ramey, H.J.: ʺWellbore Heat Transmissionʺ; JPT, April 1962. 2 Willhite, G.P.: ʺOverall Heat Transfer Coefficients in Steam Hot Water Injection Wellsʺ; JPT, May 1967. 3 Hasan, A.R. and Kabir, C.S.: ʺHeat Transfer During Two‐Phase Flow in Wellbores: Part 1 ‐ Formation Temperatureʺ, SPE ATCE Dallas TX, Oct. 1991: paper SPE 22866. 4 Hasan, A.R. and Kabir, C.S.: ʺHeat Transfer During Two‐Phase Flow in Wellbores: Part 2 ‐ Wellbore Fluid Temperatureʺ, SPE ATCE Dallas TX, Oct. 1991: paper SPE 22948. 5 Carslaw, H.S. and Jaeger, J.C.: ʺConduction of Heat in Solidsʺ, Oxford University Press, 1st. edition 1950, 2nd. Edition 1986. 6 Alves, I.N., Alhanati, F.J.S. and Shoham, O.: ʺA Unified Model for Predicting Flowing Temperature Distributions in Wellbores and Pipelinesʺ; New Orleans, Sept. 1990: paper SPE 20632. 7 Gnielinski, V.: ʺNew Equations for Heat and Mass Transfer in Turbulent Pipe and Channel Flowʺ, Int. Chem. Eng., 16, 359‐368, 1976. 8 Ramey, H.J.: ʺWellbore Heat Transmissionʺ. JPT, April 1962. 9 Willhite, G.P.: ʺOver‐all Heat Transfer Coefficients in Steam Hot Water Injection Wellsʺ. JPT, May 1967. 10 Alves, I.N., Alhanati, F.J.S. and Shoham, O.: ʺA Unified Model for Predicting Flowing Temperature Distributions in Wellbores and Pipelinesʺ; New Orleans, Sept. 1990: paper SPE 20632. 11 Gnielinski, V.: ʺNew Equations for Heat and Mass Transfer in Turbulent Pipe and Channel Flowʺ, Int. Chem. Eng., 16, 359‐368, 1976.

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SECTION 3 ANALYSIS

This section describes the analysis features in WellFlo. CHAPTER 5 Analysis .......................................................................................... 209

Chapter 5 ANALYSIS This chapter explains how to perform nodal analysis tasks in WellFlo, including setting operating conditions, running sensitivities, plotting and exporting data. Analysis ........................................................................................... 210 Operating Conditions ................................................................... 210 Sensitivities ..................................................................................... 218 Creating and Editing Sensitivities ........................................... 218 Running Sensitivities ................................................................. 220 Temperature Sensitivity to Elapsed Time .............................. 223 Export .............................................................................................. 224 Exporting Files in VFP, BHP and Other Formats .................. 224 Flowing Pressure File Output .................................................. 228 L‐Factor and Flow Correlation Tables ..................................... 228 Reports ............................................................................................ 232 Critical Unloading Rate ................................................................ 233 Pressure Drop Correlations .......................................................... 235 Pressure Drop Through a Restriction ......................................... 240 Surface Chokes ........................................................................... 240 Sub‐Surface Restrictions ............................................................ 242 ANALYSIS.log ............................................................................... 242 Flow Regime Numbers ............................................................. 244 EPS Mechanistic Correlations .................................................. 245 References ....................................................................................... 246


209

5

ANALYSIS Analysis

ANALYSIS The Analysis menu is divided into the following tasks: •

“Operating Conditions”

•

“Sensitivities”

•

“Plotting”

•

“Export”

To perform an analysis, select a task from the Analysis menu. The data entry fields for the selected task appear in the center configuration screen. In this screen, you can set up your analysis as necessary. To plot the results of the analysis, open Include in Plot. Click and drag the row pointer to select the values you want to include in the chart, and click Plot Selected.

OPERATING CONDITIONS There are four Nodal Analysis operation modes in WellFlo:

210

•

Operating Point. In Operating Point mode, WellFlo runs Pressure Drop calculations at a range of Flow Rates, starting from opposite end nodes and calculating Inflow and Outflow Pressure Curves at an intermediate point called the Solution Node. The intersection of the Inflow and the Outflow Pressure Curves provides the Operating Point (i.e. the Pressure and Flow Rate at the Solution Node) for the Well under analysis, subject to the Constraints applied (e.g. End Node Pressures and System Description).

•

Pressure Drop. Pressure Drop mode is a simpler analysis, involving a Pressure Drop calculation along the Well/Flowline system in one direction or the other at a specified flow rate, starting at a specified end node pressure. The result is the pressure at the opposite end of the system and the Pressure Profile in between.


ANALYSIS Operating Conditions

The Plot of Tubing and Casing Pressures and Temperature versus TVD is a Plot of computed Pressure and Temperature versus Depth. Other computed parameters can also be plotted versus Depth. •

Deepest Injection Point:

— Operating Point and Pressure Drop. These Nodal Analysis processes are identical to those described for Nodal Analysis Operating and Pressure modes, except that in these cases, any specified Gas‐Lift Valve Depths are ignored. WellFlo computes the Deepest Depth at which a valve could be positioned at each flow rate, subject to the constraints in the Gas‐Lift Data configuration screen (see “Gas Lift Data Configuration” on page 284). By contrast, the main Analysis options always respect the specified positions of the active Gas‐Lift Valves in the Completion diagram. •

Forced Gas Entry: This checkbox should be checked to force a Gas‐Lift Valve to open in one of the following ways:

If there is only one Active Gas‐Lift Valve, it will automatically be defined as open, even if there is insufficient Casing Pressure. If there are a number of Active Gas‐Lift Valves, but insufficient Casing Pressure exists to open any of them, Forced Gas Entry will occur at the shallowest Gas‐Lift Valve (i.e. the one most likely to open first if Casing Head Pressure was to be increased). If there are a number of Active Gas‐Lift Valves and sufficient Casing Pressure exists for one or more to be open, the deepest of these will be defined as open. This case is therefore treated the same way, regardless of whether Forced Gas Entry is on or off. If this checkbox is not checked, WellFlo will test each Gas‐Lift Valve according to the calculated Casing Pressure and Valve Differential Pressure, and will only allow a Gas‐Lift Valve to open if there is sufficient Casing Pressure. If several Gas‐Lift Valves could be open, only the deepest of them will be declared open. This option is grayed‐out (i.e. disabled) if there are no Gas‐Lift Valves in the system.


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5

ANALYSIS Setting Operating Conditions

This option is not available for Deepest Point of Injection calculations; for these calculations, WellFlo computes the Deepest Depth at which a Valve could be positioned at each Flow Rate, subject to the Constraints in the Configuration/Gas Lift Data Panel. By contrast, this Nodal Analysis option always respects the specified positions of the active Gas‐Lift Valves in the Completion diagram. •

Depth Format. This option defines the way all depth‐based plots (i.e.Pressure and Temperature versus Depth) are scaled (see Figure 5‐1).

Figure 5-1: Depth Format

Setting Operating Conditions The operation mode and other operating conditions are set in the Operating Conditions configuration screen, under the WellFlo Analysis menu.

TO SET OPERATING CONDITIONS: 1 Open Analysis in the Navigator.

212


ANALYSIS Setting Operating Conditions 2 Select Operating Conditions in the Analysis menu. The Operating Conditions menu is displayed in the center of the screen (see Figure 5‐2). Figure 5-2: Operating Conditions


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5


3 Select an Nodal Analysis Mode: •

Operating Point. This option is used to perform operating point nodal

analysis for the current well. For Operating Point mode, this means running Pressure Drop calculations at a range of flow rates, starting from opposite end nodes and calculating Inflow and Outflow pressure curves at an intermediate point called the Solution Node. The intersection of the Inflow and the Outflow pressure curves provides the Operating Point (i.e. the Pressure and Flow Rate at the Solution Node) for the well under analysis. In Operating Point mode, there are two end nodes and a Solution Node. Logic is used to keep the node selection consistent (i.e. the Top Node must be above the Bottom Node, and the Solution Node must be between the two).

i •

The Outflow part of the calculation will run from the top of the component selected as the Top Node, down to the Solution Node. The Inflow part of the calculation will run from the bottom of the component selected as Bottom Node, up to the Solution Node. The bottom of the component selected as the Solution Node is used as the end point for both calculations.

Pressure Drop. This option is used to perform pressure drop nodal

analysis for the current well. For Pressure Drop mode, this is a simpler analysis, involving a Pressure Drop calculation along the well/flowline system in one direction or the other at a specified flow rate, starting at a specified end node pressure. The result is the pressure at the opposite end of the system and the Pressure Profile in between. The plot of tubing and casing pressures and temperature versus TVD is a plot of computed pressure and temperature versus depth. Other computed parameters can also be plotted versus depth. •

Deepest Injection Point.

i

These options will be disabled if the user's current software licence is not configured for WellFlo Gas-Lift. Additionally, these options are enabled only when the Fluid Type is Oil.

— Operating Point. This option is used to perform Deepest Point of Gas Injection Operating Point nodal analysis for the current well. For the Operating Point mode, this means running pressure drop calculations at a range of flow rates, starting from opposite end nodes and calculating Inflow and Outflow pressure curves at an intermediate

214



point called the Solution Node. The intersection of the Inflow and the Outflow pressure curves provides the Operating Point (i.e. the pressure and flow rate at the Solution Node) for the well under analysis. The nodal analysis process is identical to that described for Operating mode, except that in this case, any specified Gas‐Lift Valve Depths are ignored. WellFlo computes the Deepest Depth at which a Valve could be positioned at each flow rate, subject to the constraints in the Gas‐Lift Data configuration screen. By contrast, the main Analysis options always respect the specified positions of the active Gas‐Lift Valves in the Completion diagram. — Pressure Drop. This option is used to perform Deepest Point of Gas‐Injection Pressure Drop nodal analysis for the current well. For the Pressure Drop mode, this is a simpler analysis, involving a Pressure Drop calculation along the Well/Flow Line system in one direction or the other at a specified Flow Rate, starting at a specified End Node Pressure. The Result is the Pressure at the opposite end of the system and the Pressure Profile in between. This Nodal Analysis process is identical to that described for the Pressure Operation Mode, except that in this case, any specified Gas‐Lift Valve Depths are ignored. WellFlo computes the Deepest Depth at which a Valve could be positioned at each flow rate, subject to the constraints in the Gas‐Lift Data configuration screen. By contrast, the main nodal analysis options always respect the specified positions of the active Gas‐Lift Valves in the Completion diagram.

i •

This calculation mode would normally be the prelude to a Gas-Lift Design exercise. It would be used to establish the range of Valve Depths required to allow for changing production conditions. Sensitivity to declining Reservoir Pressure, increasing Water-Cut, etc. could also be investigated here.

Forced Gas Entry: This checkbox should be checked to force a Gas‐Lift Valve to open in one of the following ways:

If there is only one Active Gas‐Lift Valve, it will automatically be defined as open, even if there is insufficient Casing Pressure.


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If there are a number of Active Gas‐Lift Valves, but insufficient Casing Pressure exists to open any of them, Forced Gas Entry will occur at the shallowest Gas‐Lift Valve (i.e. the one most likely to open first if Casing Head Pressure was to be increased). If there are a number of Active Gas‐Lift Valves and sufficient Casing Pressure exists for one or more to be open, the deepest of these will be defined as open. This case is therefore treated the same way, regardless of whether Forced Gas Entry is on or off. If this checkbox is not checked, WellFlo will test each Gas‐Lift Valve according to the calculated Casing Pressure and Valve Differential Pressure, and will only allow a Gas‐Lift Valve to open if there is sufficient Casing Pressure. If several Gas‐Lift Valves could be open, only the deepest of them will be declared open. This option is grayed‐out (i.e. disabled) if there are no Gas‐Lift Valves in the system. This option is not available for Deepest Point of Injection calculations; for these calculations, WellFlo computes the Deepest Depth at which a Valve could be positioned at each Flow Rate, subject to the Constraints in the Configuration/Gas Lift Data Panel. By contrast, this Nodal Analysis option always respects the specified positions of the active Gas‐Lift Valves in the Completion diagram. •

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Depth Format. This option defines the way all depth‐based plots (i.e.Pressure and Temperature versus Depth) are scaled (see Figure 5‐3).


ANALYSIS Setting Operating Conditions Figure 5-3: Depth Format

Calculation Nodes 4 Select and enter Calculation Nodes data: • •

Top Node. Select the top node from which calculations will be performed. Bottom Node. Select the bottom node from which calculations will be

performed. •

Solution Node. Select the node for which a solution will be calculated.

•

Top Node Pressure. The starting point pressure for the outflow part of the

calculation. •

Bottom Node Pressure. The starting point pressure for the inflow part of

the calculation. 5 Enter liquid (i.e. Oil model only) or gas (i.e. Gas and Condensate models only) Flow Rates at which the nodal analysis calculations will be performed. The defaults are 11 flow rates in a range from 5% to 95% of the AOF.


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ANALYSIS Sensitivities

In an Operating point calculation, these will be arbitrary flow rates that (hopefully) span the actual operating point/s. The flow rates used should ensure that the intersection (if any) of Inflow and Outflow curves will be seen. At least two flow rates are required for an Inflow/Outflow Analysis. 6 If necessary, click the Clear button to remove all flow rate values and enter new flow rates. Clear: Clears all flow rate values in the operating conditions configuration screen.

7 You can click Auto-Range to recalculate the flow rates based on the fill settings entered in the Rate or % of AOF.

SENSITIVITIES Creating and Editing Sensitivities The Sensitivities and Sensitivity Groups offered when the Reservoir is included in a Nodal Analysis run are dependent on the current Reservoir Configuration (i.e. there is no point in offering a Sensitivity option whose values would not be used in subsequent IPR recalculations).

TO CREATE SENSITIVITIES: 1 Open the Analysis menu in the Navigator. 2 Select Sensitivities in the Analysis menu. The Sensitivity configuration and selection screen is displayed (see Figure 5‐4).

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ANALYSIS Creating and Editing Sensitivities Figure 5-4: Sensitivities

3 Click Create under Manage Sensitivities on the Sensitivities menu. The sensitivities and sensitivity groups listed in the Sensitivities section are enabled. Selecting a group from the Sensitivities menu shows defaults in the Values section for that sensitivity. 4 Edit these defaults by directly editing the Values table or by entering From, To and Step values in the Range section. 5 Click Apply to add the new sensitivity to the Manage Sensitivities menu.

TO EDIT SENSITIVITIES: 6 Select a sensitivity from the Manage Sensitivities menu and click Edit. The sensitivities and sensitivity groups listed in the Sensitivities section are enabled. Selecting a group from the Sensitivities menu shows defaults in the Values section for that sensitivity.


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ANALYSIS Running Sensitivities

7 Edit the values by directly editing the Values table or by entering From, To and Step values in the Range section. 8 Click Apply to save your changes.

Running Sensitivities To run Sensitivity Analyses, users must select one or two sensitivities from the Sensitivity 1 and Sensitivity 2 drop‐down lists. If no sensitivities are selected, only the base case values entered in the various input fields will be used in the Nodal Analysis.

TO RUN A SENSITIVITY ANALYSIS: 1 Open Analysis in the Navigator. 2 Expand the Sensitivities menu, if necessary. Existing sensitivities are listed in the Manage Sensitivities list and are available in the drop‐down lists under Sensitivity 1 and Sensitivity 2 (see Figure 5‐5).

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ANALYSIS Running Sensitivities Figure 5-5: Manage Sensitivities

3 Select a sensitivity in the Sensitivity 1 drop‐down list. (Select a sensitivity in the Sensitivity 2 drop‐down list as well, if desired.) 4 Click Calculate to run the selected sensitivity.

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If the selection is Flow Correlation (group) and Well and Riser L-Factor (variable), there is a check performed to assess whether Automatic L-Factor matching is feasible (i.e. provided the Analysis Mode is Pressure Drop at a single Flow Rate, some measured Pressure/Depth Data has been loaded — including at least one depth covered by the range of the analysis, and Pressure is selected as one of the axis variables to be collected for plotting on the Pressure/Depth Plot).

Plotting 5 Open Include in Plot on the Analysis menu. The results of the sensitivity analysis are displayed (see Figure 5‐6).


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ANALYSIS Running Sensitivities

Figure 5-6: Include in Plot

6 Drag the row selector to select the values you want to plot in the chart. 7 Click Plot Selected. The values selected are plotted in the chart windows (see Figure 5‐7).

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ANALYSIS Temperature Sensitivity to Elapsed Time Figure 5-7: Plot Selected

The Inflow/Outflow curves are plotted in the Flow Curves plot. 8 Open any other tabs, such as the Wellbore Equipment Profile, to view the associated plots. If necessary, unpin any plots for better viewing. For more information on using WellFlo charts, see “Charts” on page 21.

Temperature Sensitivity to Elapsed Time In the WellFlo Sensitivities section, the sensitivity variable Elapsed Production Time is usually available in the Group entitled Pressure and Temperature. This variable is applied in the Temperature calculations in Nodal Analysis, which otherwise assume an elapsed Production Time of 100 hrs (i.e. for Calculated and Calibrated Models) or 200 hrs (i.e. for Coupled Model). Using different values as Sensitivities will show how dependent the Analysis Results are on this parameter.


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ANALYSIS Export

EXPORT Exporting Files in VFP, BHP and Other Formats WellFlo contains a facility to create ten specialized types of results file format, compatible with a number of widely‐used reservoir simulators.

TO EXPORT FILES: 1 Open Analysis in the Navigator. 2 Click Export in the Analysis menu to open the Exported File Information screen. The Exported File Information screen is displayed (see Figure 5‐8). Figure 5-8: Exported File Information

3 Select an export option from the drop‐down list. 4 Enter the None Table Number.

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ANALYSIS Exporting Files in VFP, BHP and Other Formats 5 Enter a file name or browse to select a file 6 Choose either DOS or Unix line separator format for the file output. 7 Choose either the Oilfield or Metric system in the Units menu. 8 Select the appropriate choice in the Basis of [VFP, BHP, etc.] Data section. For some formats, you have a choice of working with Liquid or Oil Production Rates. 9 Enter or edit the Flow Rates (minimum of one value is required). 10 Open the Gas Lift tab (only enabled for an Oil Well with a Gas‐Lift Valve) or the ESP Values tab (only enabled for an Oil Well with an ESP). You have the choice of specifying Injection Gas/Liquid Ratio, GLRi or Gas Injection Rate, Qgi. 11 For an Oil Well, open the Gas Ratios tab (not enabled for Gas Wells) and fill in the gas ratio values. For a Condensate Well, open the Oil Ratios tab and enter values for the Producing Oil/Gas Ratio, OGR. 12 Open the Pressures tab to enter Pressure Values and specify whether these are Tubing Head (At Tubing Head) or Separator (At Outlet Node) pressures using the appropriate radio button selection: 13 Open the Water Content tab. For an Oil Well, enter the Water‐Cut. For Gas and other Condensate Wells, enter values for the Water/Gas Ratio. In the Variances section, you can enter flow correlations and/or L‐Factor calibrations to be used with the specified Flow Rates and Water‐Cuts (e.g. different Correlations could be used for low and high Water‐Cuts, or Correlations could be Tuned in different ways as the Water‐Cut increases, based on calibrations against field data. This methodology is only applied to flow in the well, not the surface flowlines).

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Both Action options are available for Export to Eclipse and SIMBEST. Only the L-Factor option is available for the other export formats.

14 Check Vary correlation with rate and water cut to enter flow correlations. The Flow Correlations selection dialog box is displayed (see Figure 5‐9).


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ANALYSIS Exporting Files in VFP, BHP and Other Formats

Figure 5-9: Flow Correlations selection by rate and water cut

15 Check Vary L factor with rate and water cut to enter L factors. The L Factor selection dialog box is displayed (see Figure 5‐10).

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ANALYSIS Exporting Files in VFP, BHP and Other Formats Figure 5-10: L Factor selection by Flow Rate and Water Cut

16 To interpolate L‐Factor values between End‐Points, enter two End‐Point values and click Interpolate. The L‐Factors are interpolated linearly with Water‐Cut, and logarithmically with Flow Rate.

i

Horizontal and vertical interpolation are possible, over a whole or part row or column.

17 Click OK to close the dialog box. 18 Click OK on the Export screen. The export file can be viewed via Windows NotePad, WordPad, or similar text editor. Different screen editors react differently to the line separator characters written in the Unix format.


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ANALYSIS Flowing Pressure File Output

Flowing Pressure File Output The results are listed in the appropriate formats for the various simulators, as specified in their user manuals. A few points are worth highlighting: •

Where Mid‐Perforation Depth is written to the file, it is defined as: — BHP, IMX, SB1 and SB2 files: TVD below Wellhead/Xmas Tree — VFP files: TVD below MSL

•

If a combination of Sensitivity Values is encountered where the top‐down calculation cannot be made (usually because the Bottom Hole Pressure (BHP) would be ridiculously high, or Critical Flow is identified), an asterisk (*) is written in the Results array of the BHP file, and 1E10 is written in the VFP file.

•

Long lines of output data in exported VFP files are broken at 130 characters. Ensure that an adequate length setting exists in the Eclipse control parameters before attempting to read in the VFP file (the default is 132).

L-Factor and Flow Correlation Tables L-Factor Tables: To apply variations in L‐Factor with Water‐Cut and Production Rate based on Calibrations for a particular Well, users can set‐up a Multiple L‐Factor table. The table is stored as part of the WellFlo *.WFL Well file. In order to impose a different set of Flow Rates and Water‐Cuts for the calculations, users must modify the table Analysis — Export screen after loading the appropriate *.WFL file in WellFlo. This is because WellFlo will always use the Sensitivity Values entered in the table (i.e. if present), for the Flowing Pressure calculations on the well concerned.

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If there is no L-Factor table in the Export screen for a particular well, the Flow Rate and Water-Cut values in the Control File will be used for that well.


ANALYSIS L-Factor and Flow Correlation Tables

Flow Correlation Tables: Users may set up a Flow Correlation table in the Export screen for a particular Well, to account for variations in choice of Flow Correlation with Water‐Cut and Production Rate. The table is stored as part of the WellFlo *.WFL Well file. Entry in Control File

Description

Example

format=dos/unix

=dos: uses DOS line-break =unix: uses special Unix line break

format=dos

units=oilfield/ metric

Switches between Eclipse Oilfield and Metric Units.

Switches between Eclipse Oilfield and Metric Units.

gor=GOR1 (j) GORj

Use (j) evenly-spaced GOR values from GOR1 to GORj. The example (right) specifies five GOR values: 0.1, 0.2, 0.3, 0.4, 0.5 Mscf/STB. To specify a single value, just enter (for example): gor=0.3

gor = 0.1 (5) 0.5

qgi=Qgi1 (k) Qgi k

Use (k) evenly-spaced Qgi values from Qgi1 to Qgi k. The example (right) specifies four Qgi values: 0, 500, 1000, 1500 Mscf/day. To specify a single value, just enter (for example): qgi=500.

qgi = 0 (4) 1500

thp=THP1 (m) THPm

Use (m) evenly-spaced Tubing Head Pressure values from THP1 to THP m. The example (right) specifies three THP values: 100, 150 and 200 psia. To specify a single value, just enter (for example): thp=100.

thp = 100 (3) 200


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Entry in Control File

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Description

Example

liq=Qliq1 (n) Qliq n

Use (n) evenly-spaced Liquid Rate values from Qliq1 to Qliq n. The example (right) specifies six Liquid Rates: 1000, 2000, 3000, 4000, 5000, 6000 STB/day. To specify a single value, just enter (for example) : liq=2000.

liq = 1000 (6) 6000

wc=WCUT1 (z) WCUTz

Use (z) evenly-spaced Water-Cut values from WCUT1 to WCUTz. The example (right) specifies three Water-Cuts: 0, 0.25, 0.50. To specify a single value, just enter (for example):wc=0.25.

wc = 0 (3) 0.50

wellfilename=tabnum

Generate a VFP table using the above data for the *.WFL file whose name is wellfilename. Assign table number tabnum to this table. The VFP file will be saved as wellfilename.VFP. The example (right) will create a VFP file called AZ5.VFP for the Well file AZ5.WFL. The Table Number will be 2.

AZ5=2

wellfilename=tabnum

Generate a VFP table for another Well, using the above sensitivities, or different ones if they have been specified after the previous wellfilename entry. In this example, a second table, AZ6.VFP, will be generated from AZ6.WFL using the same sensitivities. The Table Number will be 1.

AZ6=1



Entry in Control File

Description

Example

corrdivs= w1 w2... / q1 q2...

Flow Correlation tables: A different Flow Correlation can be assigned to each Water-Cut range 0 < wc = w1, w1 < wc = w2, etc., and for each Flow Rate range Q = q1, q1 < Q = q2, etc. Users can specify up to three values (= four ranges) each for the Water-Cuts and Flow Rates. In the first example (right), the Water-Cut ranges are = 0.2, 0.2-0.4, 0.4-0.8 and > 0.8. The Flow Rate ranges are = 5000.

corrdivs= 0.2 0.4 0.8 /5000

corrdivs= w1 w2... / q1 q2...

In the second example (right), the Water-Cuts span the maximum range 0-1.0 (no values specified), and the Flow Rate ranges are = 5000 and > 5000.

corrdivs= / 5000

corrnums= n2 n3...

The Flow Correlation to be used in each of the ranges defined by corrdivs is specified by a number. The first example (right) goes with the first corrdivs example: the first four Correlations numbered 2,4,5 and 3 are assigned to the four Water-Cut ranges defined by corrdivs, for Flow Rates = 5000. The Correlations numbered 2,4,6 and 7 are assigned to these four Water-Cut ranges for Flow Rates > 5000.

Corrnums= 2 4 5 3 2 467

corrnums= n2 n3...

In the second example, since the Water-Cut has not been sub-divided in corrdivs (see above), Correlation 3 is assigned to the full Water-Cut range 0-1.0, for Flow Rates = 5000, and Correlation 5 for Flow Rates > 5000.

Corrnums=3 5


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ANALYSIS Reports

REPORTS Reports contain a summary of the input data and system description, followed by the calculated results. •

For Operating Point calculations, the pressures calculated at the Solution Node in the inflow direction and outflow direction will be listed for each flow rate, along with the Operating Point, and Depth of Gas‐Injected (i.e. provided a Gas‐Injection Analysis is being performed), on a case by case basis. The Operating Point report lists the flow rates of each Layer at each Operating Point. For Cross‐Flowing Layers in a Production Well, the Cross‐Flow Rate is listed, with a negative sign.

•

For Pressure Drop calculations, the results listing will contain the flowing Pressures and Temperatures (at each computational increment) versus Depth for each Flow Rate and each Sensitivity. The Casing Pressure is also presented to allow Pressure Drop over the completion to be examined. For Gas and Condensate wells, the Critical Unloading Rates will be reported for each sensitivity combination.

Some of these ʺcollectible parametersʺ are also part of the ANALYSIS.log output. Others, such as Liquid and Gas Velocity Numbers, can be listed only in the Report file (and Plotted against Depth).

TO VIEW ANALYSIS REPORTS: 1 Create a new or open an existing WellFlo file. 2 Open the Analysis menu in the Navigator. 3 Set up and calculate a new Nodal Analysis for the selected Well. 4 Open the Report tab to view the output report. The Report output screen is displayed (see Figure 5‐11).

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ANALYSIS Critical Unloading Rate Figure 5-11: Analysis Report

5 Click the Save Report button to save this report to the WellFlo Output sections.

CRITICAL UNLOADING RATE For Gas and Condensate wells only, the Critical Unloading Rate (i.e. the Production Rate that corresponds to the Turner Velocity at the Wellhead) is computed from the Turner Critical Velocity, which is collected for all fluid types.


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ANALYSIS Critical Unloading Rate

The Critical Unloading Rate is reported as described in the WellFlo Reports and the WELLFLO.log file (i.e. if enabled via the Application Options configuration dialog box (Settings > Options...). •

In Pressure Drop mode, Critical Unloading Rate is reported in the WellFlo output Report and WELLFLO.log for each flow rate (i.e. every Pressure Drop calculation run).

•

In Operating Point mode, Critical Unloading Rate is reported for any operating point run (i.e. Inflow/Outflow Analysis). It is also reported in the WELLFLO.log for each trial flow rate.

Technical The Turner Critical Velocity is computed at the Xmas Tree/Wellhead using the equation proposed by Turner1 and modified by Coleman et al2: Figure 5-12: Turner Critical Velocity

With the Critical Velocity (Vgc) in ft/sec, Interfacial Tension (s) in dynes/cm, and Gas and Liquid Densities (rG and rL) in lbs/ft3. This is then converted to Gas Flow Rate using Wellhead Pressure (WHP), Temperature and Tubing Inside Diameter (ID). For a Water/Gas Ratio (WGR) of zero, Coleman2 suggests that the Condensate properties should be used in the equations for Turner Critical Unloading Velocity and Flow Rate instead of those for water. Any non‐zero WGR should invoke water properties.

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ANALYSIS Pressure Drop Correlations

PRESSURE DROP CORRELATIONS There are twelve Pressure Drop Correlations available in WellFlo. Six are derived from standard theory, four have been modified in various ways (i.e. variants of the Duns and Ros, Beggs and Brill, and Hagedorn and Brown correlations), one is a hybrid (i.e. Dukler‐Eaton‐Flanigan), and one is an in‐house mechanistic model (i.e. EPS Mechanistic). The standard forms of the correlations follow the published references as closely as possible. There are three sources of Pressure Drop: •

Hydrostatic Gradient: This arises from the density of the multi‐phase column of fluids. It is calculated from a knowledge of the Liquid Hold‐Up (i.e. the proportion of the flowing area occupied by liquid), and the Densities of the Phases. It is proportional to the sine of the deviation, being zero in a horizontal pipe. Most correlations use a Flow‐Regime Map to determine the type of flow, and then use a particular correlation for the Flow‐Regime concerned to determine Hold‐Up.

•

Frictional Gradient: This arises from the drag of the fluids on the walls of the pipe. This is calculated in a specific way for each correlation, but generally uses the concept of a Friction Factor diagram (such as Moodyʹs) to calculate the Friction Factor as a function of the Reynoldʹs Number and Pipe Roughness. The Friction Factor is used to calculate the Frictional Pressure Gradient. For Annular Flow, the Pipe Roughness specified for the Tubing inside wall (i.e. Tubing Component dialog) is applied to the Tubing outside wall and the Casing inside wall.

•

Acceleration Gradient: This arises from the increasing kinetic energy of the fluids as they expand and accelerate with decreasing Pressure. This term is often negligible, but is always included in these correlations. All correlations in WellFlo use an acceleration term proposed by Beggs and Brill3, based on the mean Phase Velocities in each computational segment.


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Each correlation is described in terms of these three pressure gradient components.

i •

For the Frictional Gradient, the following correlations do not use the Wall Roughness entered in the component dialog, but compute their own Roughness Factors internally: Beggs and Brill, Beggs and Brill (no-slip), Fancher-Brown, Dukler-Eaton-Flanigan.

Duns and Ros: This follows the methods described by Brown3. The correlation makes use of a Flow‐Regime Map covering Bubble, Slug and Mist flow. There is a linear transition between Slug and Mist. Each regime has its own Hold‐Up correlation. There is no change to Hold‐Up with deviation. The Friction is calculated with liquid properties for Bubble and Slug flow, and gas properties for Mist. In Mist flow, the Wall Friction is increased due to liquid ripples on the pipe wall. This correlation is considered by some to be the best suited to Gas‐Lift stability prediction (i.e. using GLRi as Sensitivity).

•

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Duns and Ros (modified): This has a Flow‐Regime Map extended by the work of Gould et al4. This includes a new transition region between Bubble and Slug flow, and an additional Froth flow region at high Flow Rates. The Hold‐Up is considered as No‐Slip for Froth flow, and is interpolated over the Bubble‐Slug transition. The other Hold‐Up relationships are the same as the standard Duns and Ros. To model deviation, the calculated Hold‐Up is modified using the Beggs and Brill corrections (see below). The Friction is calculated by the method proposed by Kleyweg5; this uses a Monophasic Friction Factor rather than a Two‐Phase Friction Factor, but involves use of an average Fluid Velocity. This is claimed by Kleyweg to be a better method.



•

Beggs and Brill: This again follows the methodology outlined by Brown3. This correlation is unique in that it is based on a Flow‐Regime Map for horizontal flow, from which a regime is first determined as if the flow were horizontal. A horizontal Hold‐Up is then calculated by correlations. Lastly, this Hold‐Up is corrected for the actual Angle of Deviation. As the Beggs and Brill correlation models up‐flow and down‐flow, it is recommended for all pipeline applications. However, since it was not derived for vertical flow, it must be used with caution in vertical wells. The Friction calculations in Beggs and Brill use an internally‐defined Two‐Phase Smooth Pipe Friction Factor. This may be expected to under‐estimate Friction in rough pipes.

•

Beggs and Brill (no‐slip): This uses the same methodology as the standard Beggs and Brill, with the exception that the Hold‐Up used is not the horizontal Hold‐Up described above, but simply the No‐Slip Hold‐Up, without the deviation correction.

•

Beggs and Brill (modified): This also uses the same methodology as the standard Beggs and Brill, with the following changes. There is an extra flow regime of Froth flow, which (as in Duns and Ros (modified)) assumes a No‐Slip Hold‐Up. This is triggered by highly Turbulent flow. The Friction Factor is changed from the internally‐defined Two‐Phase Smooth Pipe Friction Factor to the method used in Duns and Ros (modified) — a Monophasic Friction Factor using Pipe Roughness and average Fluid Velocity.

•

Hagedorn and Brown: Again, this is as per Brown3, with the modifications to Hagedorn and Brownʹs original work recommended by the authors. These include the use of the Griffith and Wallis correlation for Bubble flow (i.e. using a simplified Flow‐Regime Map to detect Bubble flow); and the use of No‐Slip Hold‐Up, if it gives greater density then Hagedorn and Brownʹs correlation.


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There is no change to Hold‐Up with deviation. A Two‐Phase Friction Factor incorporating Pipe Roughness is used.

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•

Hagedorn and Brown (modified): This involves the adjustment of the standard Hagedorn and Brown Hold‐Up for deviation, using the Beggs and Brill correction. When Griffith and Wallisʹ Hold‐Up correlation is invoked (i.e. for Bubble flow), it is also corrected. Otherwise, this is the same as the standard Hagedorn and Brown correlation.

•

Fancher and Brown: This is a No‐Slip correlation3, with no Flow Regime Map. It has an internal Friction Factor model, which is independent of Pipe Roughness. This correlation cannot be recommended for general use. According to Brown, it is only suitable for 23/8 to 27/8 inch size tubulars. It is included in WellFlo for any historical comparisons that may be required. Generally, it differs widely from the results of the other seven correlations.

•

Orkiszewski: This is again based on the description by Brown3. This is perhaps the most sophisticated correlation, as it uses the work of Duns and Ros and Griffith and Wallis, for Mist and Bubble flow respectively (using a Flow Regime Map similar to Duns and Ros). It has an internal correlation in the Slug flow region, which is based on the approach of Griffith and Wallis. A transition between Slug and Mist flow is also modeled. The Hold‐Up is adjusted for deviation using the Beggs and Brill correction (as in the Duns and Ros (modified) and Hagedorn and Brown correlations). The Friction Factor calculation uses Wall Roughness, but varies with Flow Regime, and for Mist flow retains the Duns and Ros additional Wall Friction term, accounting for ripples in the film of liquid on the wall.



In the correlation, the default In‐Situ Water‐Cut value defined for switching from the Continuous Oil Phase equations to the Continuous Water Phase equations for Slug flow is 50%. •

Gray: This is a widely‐recommended correlation6 for Gas and Gas Condensate systems which are predominantly Gas phase (with liquid entrained as droplets). No Flow Regime Map is used, with flow being treated as a Pseudo‐Single‐Phase. Water or liquid condensate is considered to adhere to the pipe wall, resulting in a modified Roughness term.

•

Dukler‐Eaton‐Flanigan: This is a hybrid of the Dukler7 correlation for the Friction component and the Flanigan8 correlation for the Hydrostatic component. The Mixture Density is calculated using Duklerʹs equation, but with Eatonʹs9 Hold‐Up definition, and this is used in Duklerʹs term for Friction. The Liquid Density is used in Flaniganʹs term for the Hydrostatic component. The Acceleration component is modeled with the Beggs and Brill correlation. This correlation can be recommended for undulating Surface Flow, but is not suitable for downflow.

•

EPS Mechanistic: This has been formulated on physical modeling principles, and is therefore applicable to all Fluid Types, Pipe Sizes and Inclinations. However, it is not at present recommended for Annular flow. The Flow Regime Map is based on work by Wallis, Barnea, Taitel and Dukler, and it models the following: — Slug flow according to Sylvester10,with the Taitel and Barnea11 correlation for the Taylor Bubble Velocity. — Stratified flow with the Sinai12 correlation for the Interfacial Friction Factor. — Annular and Mist flow with the KLSA (or Oliemans et alsʹ) entrainment correlation, Oliemans et alsʹ13 correlation for Gas Core Velocity, the KLSA Interfacial Friction Model11, and Grayʹs6 correlation for low Liquid Hold‐Up. Bubbly and Dispersed Bubble flow incorporating Wallisʹs Drift Flux Model14.

A table of the numbers used in the ANALYSIS.log file to identify the various Flow Regimes is described in “ANALYSIS.log” on page 242 and WellFlo “Flow Regime Numbers” on page 244.


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ANALYSIS Pressure Drop Through a Restriction

PRESSURE DROP THROUGH A RESTRICTION The Pressure Drop Through a Restriction is worked out as follows. The upstream Pressure is used for Fluid Property evaluation. The Heat Capacities of the Liquid and Gas Phases are found at upstream conditions. The Sonic Velocity of the single‐phase or two‐phase (i.e. Gas‐Liquid) mixture is determined from the Heat Capacity Ratio, Cp/Cv. If the actual Throat Velocity is greater than this, the flow is critical, and if less, it is sub‐critical. Critical Flow and Sub‐Critical Flow are flagged in the Flow Regime column of the ANALYSIS.log file (i.e. if the Output to Analysis Log option is checked in Preferences of the Application Options configuration dialog box), where an entry flag of 0 = Sub‐Critical and 1 = Critical. In the case of single‐phase or nearly single‐phase (i.e. high GLR) systems only, this flag is used in a general Critical/Sub‐Critical Flow equation (i.e. Beggs15), which models the transition smoothly between the two flow types. For low GLR systems, owing to the discontinuous nature of the available Choke equations, this flag is ignored, and the Use critical flow equation checkbox settings in the Surface Equipment configuration screen are invoked (i.e. users can select between using Critical Flow equations (checked) or Sub‐Critical Flow equations (unchecked). In this case, the flag is for information only.

Surface Chokes •

For Black Oil Fluid Type (and for Gas, Condensate or Volatile Oil Fluid Types with GLR < 10,000 scf/STB), the Pressure Drop will be computed using a Critical or Sub‐Critical Flow Equation, depending on the choice made in the Surface Equipment configuration screen.

Critical Flow is handled by one of six correlations. These are listed in the following table together with the coefficients A, B, C and D: Correlation Gilbert

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A 1.89

B 10.00

C 0.546

D 1.0

ANALYSIS Surface Chokes

Correlation

A

B

C

D

Baxendell

1.93

9.56

0.546

1.0

Achong

1.88

3.82

0.65

1.0

Ros

2.00

17.40

0.50

1.0

Aussens

1.97

3.89

0.68

1.0

Corpoven (oil or volatile oil)

1.9523

8.255814

0.501022

1.0645

Corpoven (gas or condensate)

1.814859

7.700537

0.595821

0.962028

Critical Flow can also be handled by a customized correlation with user‐defined coefficients. These coefficients are used in the following equation: Pup = (B x QlD x GLRC) / (DchokeA) to determine the upstream pressure. If the Corpoven Critical Choke Correlation is selected, and the Use critical flow equation checkbox option has been checked in the Surface Equipment configuration screen, then the GLR > 10,000 scf/STB rule does not apply. The Sub‐Critical equation is used for single‐phase Gas Flow, and the Corpoven Critical Choke Correlation appropriate to the fluid type (refer to table above), is used for two‐phase flow at all values of GLR.

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Downstream Pressures cannot be determined in the case of Critical Flow, and if Critical Flow occurs in an upstream-to-downstream computation in a Production Well, the computation will stop at the Choke. The same situation applies in the case of an Injection Well, where Critical Flow occurs in the direction of injection.


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ANALYSIS Sub-Surface Restrictions

Sub‐Critical Flow is modeled using a modified version of Beggsʹ SSV15 equation. •

For single‐phase Gas, or high GLR Gas/Condensate/Volatile Oil systems (i.e. GLR > 10,000 scf/STB), flow is treated as (near) single‐phase, and Critical or Sub‐Critical Pressure Drops are computed according to the Sonic Velocity Test described above, using Beggsʹ General Equation15, regardless of the checkbox setting in the Surface Equipment configuration screen for the choke.

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If the Coupled Pressure-Temperature Model has been selected, WellFlo also accounts for the Joule-Thomson effect on the moving fluid16.

Sub-Surface Restrictions The same logic applies to Sub‐Surface Restrictions as to Surface Chokes: •

Black Oil, or low GLR Gas/Condensate/Volatile Oil systems (GLR < 10,000 scf/STB): The Critical/Sub‐Critical checkbox setting in the wellbore Equipment > Restrictions configuration screen is respected and the appropriate equation is imposed; the Sonic Velocity Test is ignored.

•

Single‐phase Gas, or high GLR Gas/Condensate/Volatile Oil systems (GLR > 10,000 scf/STB): the Sonic Velocity Test is respected and Beggsʹ General Equation15 is used; the Critical/Sub‐Critical checkbox setting in the wellbore Equipment > Restrictions configuration screen is ignored.

ANALYSIS.LOG When Output to Analysis.Log is selected in the Application Options dialog (Settings > Options...), users can view their output from WellFlo Nodal Analysis in a textual form.

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ANALYSIS ANALYSIS.log

The log files contain more details about the calculations than are provided in Analysis Report output and are intended for diagnostic purposes.

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Users are recommended not to enable these options unless absolutely necessary, since writing the Log File/s will slow down WellFlo calculations.

Successive calculation records are either appended to the previous *.LOG files during a given WellFlo session or the files can be cleared at the start of each new run, depending on the current setting of the Clear .Log every run checkbox in the WellFlo Application Options dialog. user = xxx where xxx is the directory path. The files can be viewed or edited with Notepad, by default, or a selected application. To keep a *.LOG file, use the Save As option in Notepad or the current viewer to save it under a new name; otherwise, it will be over‐written (default setting) the next time that Nodal Analysis calculations are performed in WellFlo. If Clear .Log every run is unchecked in the Application Options dialog, the calculation details will be appended to the existing *.LOG file. The ANALYSIS.log output has been formatted (tabbed) to be read into a spreadsheet so that the calculations can be analyzed in more detail. To read the data into a spreadsheet, select the appropriate filter for tab‐separated data and open ANALYSIS.log: The parameters currently listed are: •

Pressures and Temperatures

•

In‐Situ Flow Rates, Densities and Viscosities of each Phase

•

In‐Situ Phase and Superficial Velocities

•

Hydrostatic, Frictional, Acceleration and Total Pressure Gradients

•

No‐Slip and In‐Situ Liquid Hold‐Ups

•

Flow Regime Identifiers

•

Erosional Velocity


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ANALYSIS Flow Regime Numbers

Flow Regime Numbers The Flow Regime Numbers are written to the ANALYSIS.log. They can be optionally ʺcollectedʺ and plotted versus Depth (i.e. Measured Depth (MD) or True Vertical Depth (TVD)) for well components, and versus the Length from Wellhead (or the Elevation Above MSL) for surface components. Each Flow Correlation has Flow Regime Numbers as illustrated in the following tables: Flow Regime Number Correlation

1

2

3

4

Duns and Ros (std)

Plug/Bubble/ Froth

Slug/Froth

Mist

Transition

Duns and Ros (mod)

Bubble/Plug

Bubble/Plug with Heading

Bubble/Slug

Slug with Heading

Slug

Beggs and Brill (std)

Segregated

Intermediate

Distributed

Transition

Dispersed

Beggs and Brill (mod)

Segregated

Intermediate

Transition

SemiDispersed

Beggs and Brill (no-slip)

Segregated

Intermediate

Distributed

Transition

Dispersed

Bubble

Not Bubble

Mist

Transition

Hagedorn and Brown (std and mod) Fancher and Brown Orkiszewski

All Regimes Bubble

Gray

Two-Phase

Dukler-Eaton-Flanigan

Two-Phase

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Slug

5

ANALYSIS EPS Mechanistic Correlations

Flow Regime Number Correlation

6

7

8

9

10

Gas

Liquid

Gas

Liquid

Gas

Liquid

Gas

Liquid

Beggs and Brill (no-slip)

Gas

Liquid

Hagedorn and Brown (std and mod)

Gas

Liquid

Fancher and Brown

Gas

Liquid

Orkiszewski

Gas

Liquid

Gray

Gas

Liquid

Dukler-Eaton-Flanigan

Gas

Liquid

Duns and Ros (std) Duns and Ros (mod)

Froth

Transition

Mist

Beggs and Brill (std) Beggs and Brill (mod)

Froth

Dispersed

Distributed

EPS Mechanistic Correlations Flow Regime Number Correlation

1

2

10

20

21

22

EPS Mechanistic

Gas

Liquid

Bubbly

Intermittent

Elongated Bubble

Slug

Flow Regime Number Correlation

30

40

41

50

51

52

EPS Mechanistic

Dispersed Bubble

Annular

Mist

Stratified

Stratified Smooth

Stratified Wavy


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ANALYSIS References

REFERENCES 1 Turner, R.G.: ʺAnalysis and Prediction of Minimum Flow Rate for the Continuous Removal of Liquids from Gas Wellsʺ; JPT, Nov. 1969, Trans. AIME 246. 2 Coleman, S.B., Clay, H.B., McCurdy, D.G., and Norris III, H.L.: ʺA New Look at Predicting Gas‐Well Load‐Upʺ; JPT, March 1991. Also available as ʺUnderstanding Gas‐Well Load‐Up Behaviorʺ, SPE 20281, 1991. 3 Brown, K.E. & Beggs, H.D.: ʺThe Technology Of Artificial Lift Methodsʺ; Volume 1. Penwell Books 1977. 4 Gould, T.L., Tek, M.R. and Katz, D.L.: ʺTwo ‐ Phase Flow Through Vertical, Inclined or Curved Pipeʺ; JPT, August 1974. 5 Kleyweg. D. et al.: ʺGas‐Lift Optimisation ‐ Claymore Fieldʺ; Offshore European Conference, 1983: Paper SPE 11885. 6 Gray: ʺ Appendix B: Vertical Flow Correlation ‐ Gas Wellsʺ; API Usersʹ Manual for API 14B, 2nd edition, API, Dallas, June 1977. 7 Dukler, A.E.: ʺGas‐Liquid Flow in Pipelinesʺ; American Gas Association, Am. Pet. Inst., Vol. 1: Research Results (May, 1969). 8 Flanigan, O.: ʺTwo‐Phase Gathering Systemsʺ; Oil and Gas Journal (March 1958). 9 Eaton, B.A. et al: ʺThe Prediction of Flow Patterns, Liquid Holdup and Pressure Losses Occurring During Continuous Two‐Phase Flow in Horizontal Pipelinesʺ; Trans AIME (1966). 10 Sylvester, N.D.: ʺA Mechanistic Model for Two‐Phase Vertical Slug Flow in Pipesʺ; J. Energy Resources Tech., 109, 206‐213 (1987). 11 Taitel, Y., Barnea, D. and Dukler, A.: ʺModelling Flow Pattern Transitions for Steady Upward Gas‐Liquid Flow in Tubesʺ; A. I. Ch. E. J., 26, 345‐354 (1980). 12 Sinai, Y.L.: ʺA Charnock‐Based Estimate of Interfacial Resistance and Roughness for Internal, Fully‐Developed Stratified Two‐Phase Horizontal Flowʺ; Int. J. Multiphase Flow, 9, (1), 13‐19 (1983).

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ANALYSIS References 13 Oliemans, R.V.A., Pots, B.F.M. and Trompe, N.: ʺModelling of Annular Dispersed Two‐ Phase Flow in Vertical Pipesʺ; Int. J. Multiphase Flow, 12, (5), 711‐732 (1986). 14 Wallis, G.B.: ʺOne Dimensional Two‐Phase Flowʺ, McGraw‐Hill, New York, 1969. 15 Beggs, H.D.: ʺProduction Optimizationʺ; Section 3, VII, A. OGCI Publications, Tulsa, 1991. 16 Alves, I.N., Alhanati, F.J.S. and Shoham, O.: ʺA Unified Model for Predicting Flowing Temperature Distributions in Wellbores and Pipelinesʺ; New Orleans, Sept. 1990: paper SPE 20632.


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248

ANALYSIS References


SECTION 4 ARTIFICIAL LIFT

This section provides instructions for creating ESP and Gas Lift models in WellFlo. CHAPTER 6 ESP ................................................................................................... 251 CHAPTER 7 Gas Lift ............................................................................................ 283

Chapter 6 ESP This chapter how to configure, design and analyze an ESP well model in WellFlo. WellFlo ESP Overview .................................................................. 252 ESP Design and Analysis Overview ........................................... 253 Designing an ESP Installation .................................................. 253 Analyzing an ESP Installation .................................................. 254 ESP Data Configuration ................................................................ 255 Pump Environment — Design Mode ...................................... 256 Wear Factors and Efficiencies ................................................... 258 Pump Calculation Options ....................................................... 261 ESP Analysis Mode ....................................................................... 264 Pump Environment — Analysis Mode ................................... 265 ESP Pump and Motor Files .......................................................... 269 Editing esppump.dat ................................................................. 269 Editing espmotor.dat ................................................................. 271 ESP Design ...................................................................................... 273 Optimizing Pump Performance ............................................... 275 Vary Depth ..................................................................................... 280 References ....................................................................................... 282


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ESP WellFlo ESP Overview

WELLFLO ESP OVERVIEW The ESP module adds the capability of modeling ESP‐lifted wells to the WellFlo capabilities. Two modes of ESP modeling are provided: •

ESP Design

•

ESP Analysis/Diagnosis

WellFlo takes as its input a description of: •

The Reservoir

•

The Well Completion (i.e. the hardware within the well)

•

The Surface Components (i.e. Pipelines, etc.).

This information is combined with fluid properties data. The program then performs calculations to determine the pressure and temperature of the fluids through the Reservoir, Wellbore and Flow Lines. All WellFlo features are available when modeling ESPs, which means that ESPs can be studied with respect to all applicable WellFlo sensitivities, in addition to ESP‐specific sensitivities. WellFlo provides a very easy means of comparison between ESP‐lifted and Gas‐lifted wells, since similar well models can be built (i.e. Reservoir, Completion, Surface Facilities and PVT), then quickly altered to include an ESP or Gas‐Lift Valves.

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ESP ESP Design and Analysis Overview

ESP DESIGN AND ANALYSIS OVERVIEW There are two main types of ESP‐specific applications in WellFlo: •

Designing an ESP installation. This means sizing the pump and selecting a pump/motor combination based on power consumption. Selection of suitable components is made from a catalog of Manufacturersʹ data.

•

Analyzing an existing ESP. In this mode, the pump and motor are already selected for the Well, but users wish to run sensitivity studies, either for pump variables (e.g. frequency) or other variables, such as Water‐Cut (WCT) or Wellhead Pressure (WHP).

Designing an ESP Installation In this mode, an ESP is to be inserted in a well, without knowing which size of pump or motor will be required. Users also enter the flow rate they wish to achieve. The program calculates which pumps and motors will meet the set criteria, then users can select a combination from a drop‐down list based on correct sizes, capacities, power consumptions and efficiencies. The data entry requirements fall into two categories — General and ESP‐specific: General Data •

Reservoir

•

Well Completion

•

PVT

ESP‐Specific Data •

Design Production Rate

•

Operating Frequency

•

Range of pump Outside Diameters (ODs) to be considered

•

There are also some calculation options for wear factors and corrections for viscosity or free gas


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ESP Analyzing an ESP Installation

The calculation selects suitable pumps on the basis of: •

Pump OD lying between the user‐defined lower and upper limits.

•

Pump Capacity at the Design Frequency spans the Design Rate.

•

Number of Stages required is not greater than the number which the pump can be fitted with.

•

Pump Shaft Horsepower required does not exceed the specified limit.

•

Free gas through the pump does not exceed a critical limit (optional).

The motor selection is based on: •

Motor OD between the user‐defined lower and upper limits.

•

Pump Horsepower required can be supplied by the motor.

A pump and motor selection can then be made from a drop‐down list of suitable combinations. The number of stages required for each pump, the power requirements and the motor electrical power required for each motor/pump combination are all displayed. Users can fine‐tune the Design (e.g. for a different Operating Frequency, Number of Stages, etc.), if required, and may also further extend the Design scope by studying the variation of key properties against the Setting Depth of the ESP.

Analyzing an ESP Installation This calculation mode is part of WellFlo Analysis, but with the ESP included as an integral part of the Reservoir‐Well‐Surface Model. The ESP‐specific sensitivity variables are added to the standard WellFlo sensitivity variables. These ESP‐specific sensitivity variables include:

254

•

Frequency, for Variable Speed Drive applications

•

Number of Stages

•

Gas Separator Efficiency

•

Pump and Motor Wear Factors

•

ESP Setting Depth


ESP ESP Data Configuration

For each sensitivity run, the Well Operating Rate and the Motor Current (Amps) can be displayed together with the Pump Discharge and Tubing Intake curves. The maximum and minimum flow rates for the pump also are displayed, so users can see how close to these limits the pump is operating, over a range of sensitivity values.

ESP DATA CONFIGURATION The ESP Data configuration screen is used to view, enter and edit surface ESP data. The ESP Data configuration screen is added to the Navigator when ESP is selected for the Artificial Lift Method in the Well and Flow Type configuration screen.

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All options pertaining to WellFlo-ESP will be disabled if the current software license is not configured for WellFlo-ESP. The ESP and GLV options are licensed separately within WellFlo; users with a basic license will not have access to these.

There is an optional Emulsion Viscosity Correction available for ESPs via the Fluid Parameters configuration screen (see “Emulsion Viscosity:” on page 81). In Design Mode, the Design pump only option is selected (see Figure 6‐1). Three types of data can be entered: •

Pump Environment. Used to enter Setting Depth, size constraints and design Operation Frequency.

•

Wear Factors/Efficiencies. Used to apply modifiers to account for pump wear or motor wear.

•

Calculation Options. Used to apply (optional) Correction Factors for viscosity or free gas during the Design Calculations stage.

From the ESP Data configuration screen, select Design Pump only to design an ESP. When selected, the Analysis Equipment section is removed and normal nodal analysis calculations will treat the pump as non‐existent, so users can then perform ESP Design to find a suitable pump.


255

6

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ESP Pump Environment — Design Mode

Pump Environment — Design Mode The first step is to enter the range of pump and motor sizes that will form the basis of the selection process. Only pumps and motors with Outside Diameters (O.D.s) falling between the specified minimum and maximum values will be selected in the Design run; these values are specified in the Min Equ’t O.D. and Max Equ’t O.D. data entry fields respectively. Enter the range required. Normally the maximum will correspond to the casing Inside Diameter (ID) minus the clearance for cable that is required. The Max Equ’t O.D. must be greater than the Min Equ’t O.D.. Users also can enter a nominal range to span the expected size of the pump/motor they wish to install.

TO ENTER PUMP ENVIRONMENT DATA: 1 Open the Configuration menu in the Navigator. 2 Select the ESP Data configuration screen from the Model Navigator. The ESP Data configuration screen is displayed (see Figure 6‐1).

256


ESP Pump Environment — Design Mode

Figure 6-1: ESP Data Configuration - Design Mode

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The Analysis Equipment area is disabled in Design Mode, since a Pump/Motor combination has not yet been selected. If a suitable Pump/Motor combination has already been identified, then Analyze pump should be selected. See “Pump Environment — Analysis Mode” on page 265.


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ESP Wear Factors and Efficiencies

3 Fill in the following Pump Environment data: •

Measured Depth. The length from the wellhead at which the surface ESP is

situated. Changing the Measured Depth causes an error flag to be displayed when the minimum casing Inside Diameter (ID) at the new Measured Depth is smaller than the Max Equ’t O.D. entered. •

Max Equ’t OD. The maximum Outside Diameter (OD) of the pump and motor to be used. Normally the maximum will correspond to the casing Inside Diameter (ID) minus the clearance for Cable that is required. If this is changed to a diameter larger than the minimum casing Inside Diameter (ID), then an error flag is generated until the Max Equ’t O.D. is reset to that of the minimum Casing Inside Diameter (ID) between the Xmas Tree/Wellhead and the pump depth.

•

Min Equ’t OD. The minimum Outside Diameter (OD) of pump and motor to

be used. This field should be set to zero if a minimum is not to be enforced. Only pumps and motors whose ODs fall between these two values will be selected in the Design run. Some pump/motor combinations have different nominal Outside Diameters (ODs). For example, pumps of 3.372" and 3.996" both work with 3.75" motors. To ensure that only one of these pump/motor combinations are selected, users would need to enter a minimum/maximum of 3.3"/3.8", or 3.7"/4" respectively.

•

Operation Frequency. The operating frequency for the pump and motor.

This is the supply frequency for which the pump and motor will be sized. At a later stage, in Analysis Mode, the effects of frequency variation on the Pump Performance can be seen. •

Pump Name. A name to describe the component (e.g. Surface ESP).


Wear Factors and Efficiencies There are five controls and entries in this section; these are used to control three types of calculation modification: Pump Efficiency:

258



Pump Wear Factor is a modifier to the Pump Performance. When it is 1.0, no modification is made. When it is less than 1.0, the Pump Performance is degraded, as controlled by the Head Factor or Power Factor selection buttons: •

If Head factor is selected, the Pump Head is degraded by the Wear Factor (i.e. the Head produced at a given flow rate (from the Performance Curve) is multiplied by the Wear Factor, and the Power Input required remains unmodified. This would normally be the case for a worn pump.

•

If Power factor is selected, the Pump Head remains unmodified, but the power required is multiplied by (1/Wear Factor). This can be used to approximate the extra power taken‐up by a Gas Separator.

Thus, a Wear Factor of 0.8 could either: •

Degrade the Head to 80% of the manufacturerʹs figure, or

•

Increase the Power required to (1/0.8) = 125% of the manufacturerʹs figure.

Motor Wear: The Motor Wear Factor is a modifier to the Motor Current required for a given Power. It has the effect of increasing the Heat Dissipation of the motor (e.g. if a value of 0.9 is entered here, the Motor Current for a given power requirement is increased to (1/0.9) = 111% of the unmodified figure; the excess (11% here) is dissipated as heat). Gas Separator: The last two controls are concerned with Gas Separation. Check Gas separator present to model a Gas Separator below the pump. If this option is selected, the associated field, Separator efficiency will be enabled and can be used to input the fraction of Free Gas at the ESP Intake Conditions that will be split‐off from the well stream and assumed to be vented up the annulus (e.g. if the Separator Efficiency is set at 0.75, then 75% of the Free Gas will be split‐off from the well stream).

TO ENTER WEAR FACTOR/EFFICIENCIES: 1 Open the Configuration menu in the Navigator. 2 Select the ESP Data configuration screen from the Model Navigator. The ESP Data configuration screen is displayed (see Figure 6‐2).


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6

6



3 Fill in the following Wear Factor/Efficiency data: •

Pump Wear Factor. A value to allow for the degradation of the pump

stages due to such factors as scaling, stage abrasion, etc. The Pump Wear Factor is a modifier to the Pump Performance. When it is 1.0, no modification is made. When it is less than 1.0, the Pump Performance is degraded, as controlled by the Head Factor or Power Factor selection buttons. •

Head Factor. Select this option to decrease the Pump Head by the Pump

Wear Factor (i.e. the Pump Head produced at a given flow rate (from the performance curve) is multiplied by the Pump Wear Factor, and Pump Power Input Requirement remains unmodified). •

Power Factor. Select this option to increase the Pump Power Input

Requirement by the Pump Wear Factor. The Pump Head remains unmodified, but the Pump Power Input Requirement is multiplied by 1/Pump Wear Factor. This can be used to approximate the extra power taken up by a gas separator.

260


ESP Pump Calculation Options

•

Motor Wear Factor. A value to allow for the degradation of the motor itself

due to such factors as overloading, cable wear, etc. This value will decrease the efficiency of the motor, thereby increasing the power it requires. The Motor Wear Factor is a modifier to the motor current required for a given power. It has the effect of increasing the heat dissipation of the motor, since any excess power will be dissipated as heat. •

Gas separator present. Check if a gas separator is being used below the motor to remove free gas. If this option is selected, the Separator efficiency field is enabled for input.

•

Separator efficiency. This field is only enabled if the Gas separator present

is checked and is used to input the fraction of Free Gas at the ESP Intake Conditions that will be split off from the well stream and assumed to be vented up the annulus. 4 Click Apply to save your changes.

Pump Calculation Options The last group of controls for Design Mode are the three Calculation Options at top right. These control the optional Viscosity and Gassiness corrections. •

Viscosity corrections. This checkbox enables the WellFlo‐ESP Viscosity Corrections for ESP calculations. The selection made here applies to both Design Mode and Analysis Mode.

•

Gassiness corrections. This checkbox enables the WellFlo‐ESP Free Gas Corrections for ESP calculations. Again, the selection here applies to both Design Mode and Analysis Mode.

TO SET CALCULATION OPTIONS: 1 Open the Configuration menu in the Navigator. 2 Select the ESP Data configuration screen from the Model Navigator. The ESP Data configuration screen is displayed (see Figure 6‐3).


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6

6



3 Set the following Calculation Options: •

Viscosity corrections. Check to use Viscosity Corrections on the pump

calculations.

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These Viscosity Corrections are important for oils heavier than about 20 degrees API. Highly viscous oils have a degrading effect on the pump performance. This takes the form of a reduction in Flow Capacity, a decrease in Head and a decrease in Efficiency.

The WellFlo‐ESP Viscosity Corrections are based on work by the American Hydraulics Institute1. This work suggests three correction factors be applied to the pump performance: Capacity modifier, Head modifier and Efficiency modifier — all less than 1.0. The magnitude of all the modifiers is a function of the specific viscosity of the fluid passing the pump (this is a function of Viscosity, Head per Stage and Flow Rate).

262



The magnitude of the Head modifier is in addition a function of the specific speed of the pump (this is a function of the Flow Rate and Head per Stage). The modifiers can be as much as 0.5 in highly viscous systems, and this has the effect of both seriously downgrading the pump performance and increasing the amount of energy lost as heat. There is an option to force the mixture viscosity (i.e. either the averaged or emulsified viscosity), used in the ESP calculations, to revert to the Water Viscosity above a specified water‐cut. •

Gassiness corrections. Check to use Gassiness Corrections according to

C.E. Dunbarʹs2 critical Vapor‐Liquid Ratio (VLR) curve on the pump calculations. The existence of free gas in the fluid also has a degrading effect on the pump performance. WellFlo‐ESP incorporates an algorithm for both the Head degradation due to the presence of free gas and a ʺcriticalʺ free gas ratio above which the pump should not be operated. Again, this is an optional calculation, so users can examine the effects of using or ignoring the free gas corrections. The default thresholds are 1.0 and 2.0 and Dunbarʹs recommended values are 0.8 and 2.0. The method works by using an algorithm to calculate the ʺcritical free gas ratio,ʺ which is roughly proportional to the pressure in the pump (i.e. the higher the pressure, the more free gas that can be pumped). This critical ratio is compared to the actual free gas/liquid ratio at in‐situ conditions. For an actual free gas/liquid ratio below 1.0 times critical, no degradation is made; between 1.0 and 2.0, a degradation is made; and above 2.0 times critical, the calculation stops and an error condition is generated. These values are the default values that WellFlo uses — they can be edited by users to reflect the actual situation.

i

Gassiness Corrections are important on pumps without gas separators (or with inefficient ones) operating below the bubble-point pressure, with a significant in-situ VLR.

•

Upper threshold. If Gassiness Corrections are enabled, this is the maximum ratio of actual VLR to critical VLR at which the free gas chokes the pump.

•

Lower threshold. If Gassiness Corrections are enabled, this is the minimum ratio of actual VLR to critical VLR at which pump head degradation begins to take place.


263

6

6

ESP ESP Analysis Mode

Between the Lower Threshold and Upper Threshold, straight line head degradation takes place according to this equation: Headʹ = Head x (Upper ratio ‐ Actual ratio) / (Upper ratio ‐ Lower ratio)

i

The Head does not degrade at an Actual Ratio equal to the Lower Threshold, and degrades to zero at an Actual Ratio equal to the Upper Threshold.


ESP ANALYSIS MODE In Analysis Mode, the ESP Data configuration screen is used to enter extra information that WellFlo‐ESP needs to know in order to analyze the ESP. When users select the Analyze pump option, the Analysis Equipment area of the screen (where the ESP and Motor are specified) is enabled for editing. There are three cases when this is required: •

If users wish to enter pump and motor data without performing ESP Design first (e.g. to model an existing well).

•

If users wish to change the existing pump selection at any time.

•

When users have selected a pump and motor at the end of a Design Mode run, users can review the selected pump before proceeding (e.g. this might be done to modify the Number of Stages or the Motor Nameplate Rating, which WellFlo‐ESP has selected).

Most of the functions are identical in Design Mode and Analysis Mode, but the Pump Environment and Analysis Equipment areas are treated differently between the two modes.

264


ESP Pump Environment — Analysis Mode

Pump Environment — Analysis Mode The two entry fields, Min Equ’t O.D. and Max Equ’t O.D. are the same as in Design Mode (see “Pump Environment — Design Mode” on page 256). In Analysis Mode, this equipment O.D. size range is used to restrict the choice of pumps and motors in the Analysis Equipment Pump model and Motor model selections. If users already know which pump they require, they can just expand the size range to ensure it covers the required pump. The Operation Frequency is the frequency required to perform the base case Analysis of the pump and motor. After the Design process, users can then enter Analysis and investigate the effects of varying the frequency on the Pump Performance, by performing sensitivity runs. This field is linked to the Analysis Equipment area of the screen, so when users change this frequency, the displayed pump and motor characteristics change to reflect the new frequency.

Selecting Analysis Equipment This section of the screen is enabled only if Analyze pump is selected). It allows users to select different pumps and motors from the database and specify Number of Stages and Nameplate Rating.

TO SELECT AN ESP AND MOTOR: 1 Open the Configuration menu in the Navigator. 2 Select the ESP Data configuration screen from the Model Navigator. The ESP Data configuration screen is displayed (see Figure 6‐4). 3 If necessary, select Analyze pump to open the Analysis Equipment section of the screen.


265

6

6

ESP Selecting Analysis Equipment

Figure 6-4: ESP Data Configuration — Analysis Equipment

4 Select a pump to be analyzed from the Pump model drop‐down list. The list of pumps is arranged by Manufacturer and each entry contains a Model Name ‐ Manufacturer Name (e.g. A230 ‐ Reda).

i

Only pumps with ODs between the Min/Max Equipment OD specified in the Pump Environment section will be shown. If no pumps exist in the range specified, the Pump Model field will be blank.

The selected Pump model, along with its Min and Max flow rates and Number of stages, is shown and plotted in the Analysis Equipment section (see Figure 6‐5).

266



Figure 6-5: ESP Data Configuration — Analysis Equipment

•

Min/Max flow rate. These fields display the manufacturerʹs minimum and maximum recommended in‐situ total flow rates through the pump. These fields are linked to the Operation Frequency field specified in the Pump Environment section and show the actual rating at the frequency entered (e.g. if users have the first pump in the database selected, the A230‐Reda, then at 60Hz, it has a recommended flow capacity range of 100‐350 bbl/day. If you change the frequency to 66Hz (+10%), the range shows 110‐385 bbl/day (also +10%)).

i

Users are advised to contact the pump Manufacturer before operating a pump outside its recommended range.

5 Enter the Number of stages at which to operate the pump. This should be a suitable value between the minimum and maximum number allowed for this pump.


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6


6 Select a motor model to power the pump from the Motor model drop‐down list. The models presented are constrained by the Min and Max Equ’t O.D. specified in the Pump Environment section. The list includes all of the motors that satisfy the O.D. range; it is not restricted by the Pump Manufacturer Name. 7 Select the Nameplate rating for the motor. The drop‐down list contains all the motor nameplate specifications possible for the motor series currently selected. It will default to the first nameplate on the list if a new motor series is selected (i.e. 60Hz rating). •

Operating rating. This field displays the Nameplate Rating selected, modified by the Operation Frequency specified in the Pump Environment section. This enables you to select a Nameplate Rated Motor from the list (at the manufacturersʹ design frequencies), while also viewing the actual Nameplate Rating the motor will have at the user‐defined Operation Frequency (e.g. if an Operation Frequency of 66 Hz has been specified and the first pump and motor in the database are selected, the A230‐Reda and 375 Series‐Reda with Nameplate Rating 7.5 hp, 410 V, 14A, the Operation Rating will not be 7.5 hp, 410 V, 14A at 60Hz, but 8.25 hp, 451 V, 14A at 66Hz (i.e. 10% higher power and terminal voltage at the same current).

8 Select the standard Cable size required to carry power down to the pump.

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The Voltage Loss/Amp/1000 ft for each cable size is stored in a file espcable.dat supplied with WellFlo. You can edit the values or add new cable sizes, if required. However, the values entered must be in Volts/Amp/1000 ft, regardless of the Units System being used. A maximum drop of 30V/1000ft usually is recommended.

9 Click Plot to plot the ESPʹs Performance Curve, at the user‐defined Operating Frequency and Number of Stages, to give an approximation of how the pump may perform during full Nodal Analysis. The plot displays: — Head on the left axis — Power (Motor Load) on the right axis — Minimum and Maximum Flow Rates as vertical dashed lines, with Flow Rate as the abscissa. The title shows the Pump Name, Design Stages and Operation Frequency for which the plot is valid. 10 Click Apply to save your changes.

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ESP ESP Pump and Motor Files

ESP PUMP AND MOTOR FILES The pump and motor files (i.e. esppump.dat and espmotor.dat) are installed as text files that can be edited (e.g. to add a new pump). If required, users can permanently delete pumps or motors from these files, using a text editor (e.g. if a particular pump/motor is obsolete). This is not recommended, but it is described in “Editing esppump.dat” on page 269 and “Editing espmotor.dat” on page 271.

Editing esppump.dat This procedure requires users to edit the text file esppump.dat.

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The read-only attribute of the file must be disabled first.

The file is arranged by Manufacturer, as follows: [manufacturer-name] [pump-name] [locked] [OD] [design-freq] [design-stages] [q-min] [q-max] [max-hp] [number-rates] [rates] [head-coords] [power-coords] [num-stages] END [pump-name] [locked] [OD] [design-freq] [design-stages] [q-min] [q-max] [max-hp] etc. END END


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ESP Editing esppump.dat

where the Pump details are as follows: [manufacturer-name] ::=[text string] [pump-name] ::=[text string] [locked] ::=[number: 1 = locked, 0 = unlocked] [OD] ::=[number](feet) [design-freq] ::=[number](Hz) [design-stages] ::=[number] [q-min] ::=[number](BPD) [q-max] ::=[number](BPD) [max-hp] ::=[number](HP) [number-rates] ::=[number] [rates] ::=[numbers](BPD) [head-coords] ::=[numbers](FT) [power-coords] ::=[numbers](HP) [num-stages] ::=[number] END marks the end of each Pump Models data set. Put two consecutive END lines to mark the end of a Manufacturers Pump List. Enter a new [manufacturer-name] on the next line to start a new Manufacturers List. If [number-rates] = 12, there are 12 entries in the Rates, Head and Power lines. For example: REDA A230 1 0.28100 60.00 100 100.0 350.0 32.0 12 25.000 50.000 75.000 100.000 150.000 200.000 250.000 300.000 350.000 383.333 416.667 450.000 1740.122 1792.7771813.4901804.768 1709.034 1525.612 1274.542 975.860 649.607 426.681 206.345 -5.465 3.850 4.276 4.645 4.961 5.434 5.708 5.795 5.706 5.456 5.204 4.889 4.514 94118 142 166 190 214 238 260284 308 310 332 356 380 404428 452 476 498 522 546 570594 END

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ESP Editing espmotor.dat

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Users can edit this file to remove ESP Manufacturers or enter new user-defined ESP data. However, eP does not recommend that users attempt this unless absolutely necessary, since WellFlo-ESP does not have an error checking facility for this file.

Editing espmotor.dat This procedure requires users to edit the text file espmotor.dat.

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The read-only attribute of the file must be disabled first.

The file is arranged by Manufacturer, as follows: [manufacturer-name] [motor-name] [locked] [OD] [design-freq] [HP] [volts] [amps] [HP] [volts] [amps] .. .. END [motor-name] [locked] [OD] [design-freq] [HP] [volts] [amps] .. etc. .. END END


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ESP Editing espmotor.dat

where the Motor details are as follows: [manufacturer-name]=[text string] [motor-name] =[text string] [locked] =[number: 1 = locked, 0 = unlocked] [OD] =[number] (feet) [design-freq] =[number] (Hz) [HP] =[number] [volts] =[number] [amps] =[number] END marks the end of each Motor Models data set. Put two consecutive END lines to mark the end of a Manufacturers Motor List. Enter a new [manufacturer-name] on the next line to start a new Manufacturers List. For example: REDA 375 Series 10.315 60 7.5 410 14 10.5 390 20.5 15 400 28 ... 127.5 1850 51 END

!

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Users can edit this file to remove Motor Manufacturers or enter new user-defined Motor data. However, eP does not recommend that users attempt this unless absolutely necessary, since WellFlo-ESP does not have an error checking facility for this file.


ESP ESP Design

ESP DESIGN The ESP Design screen is used to perform pump and motor selection and sizing. The options are similar to conventional Nodal Analysis, but with some special ESP functions.

TO DESIGN ESP MODELS: 1 With an ESP well file open, open the Design menu in the Navigator. The ESP Design screen is opened (see Figure 6‐6). Figure 6-6: ESP Design

ESP Design is performed by Nodal Analysis as bottom‐up and top‐down calculations to the ESP, and then Sizing a Pump to supply the missing pressure. The Operating Nodes section allows users to set the Top Node and Bottom Node. The defaults are Outlet Node and Reservoir, respectively.


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ESP ESP Design

If the Bottom Node is the Reservoir, its pressure cannot be entered here as it is set via the Reservoir Layers Data — General configuration screen (see “Setting General Parameters” on page 131). The other choices of Bottom Node and Top Node have their pressures defined in the Top Node and Bottom Node pressure fields: •

Top Node Pressure. The starting point pressure for the outflow part of the

calculation. •

Bottom Node Pressure. The starting point pressure for the inflow part of

the calculation. Adjustments to recommended pump flow rate: When choosing a pump for the well, users may want to pick one that initially runs slightly above the Manufacturerʹs recommended flow rate range, then as the reservoir depletes, the flow rate will drop back into the optimum Operating Range. To specify this, users can enter percentage modifiers in the Adjustments to recommended pump flow rate area.

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Users should consult their Pump Supplier about any conclusions drawn from specifying the modified minimum and maximum Flow Rates.

2 Enter the Design liquid rate, which is the Liquid Flow Rate (at standard conditions) at which the ESP Design calculation will be performed. ESP Design works at a single Design Liquid Flow Rate. This is entered in terms of total liquids (i.e. Oil and Water).

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Neither multiple Flow Rates nor any Sensitivities, other than Variable Setting Depths, can be run while performing a Design run.

In order to estimate the Design Rate in an ʺunknownʺ well, users can run an Operating point nodal analysis with the ESP set to Design Pump Only in the ESP Data configuration screen, which effectively removes it from the calculation and allows users to see the well performance with no ESP installed. This will give a good indication of the Target Rate required for the Pump Sizing.

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ESP Optimizing Pump Performance

Function Button Section: •

•

Correlations. For any mode of calculation involving line Pressure Drop, the Flow Correlations must be selected via this button, which generates the Nodal Analysis Correlations dialog; this is used to select from five categories of Correlation. Results. Select this button to generate the View Nodal Analysis Results

dialog. 3 Click Calculate to perform the Design run. This runs the Nodal Analysis top‐down and bottom‐up calculations, and sizes pumps of the appropriate diameter and rating for the required Flow Rate and Head.

Optimizing Pump Performance This screen is used to Optimize a Designed Pump for the conditions it will operate in. The dialog displays the Fluid Velocity Past the Motor for a selected pump and flow rate. This facility allows users to Optimize the configuration of the selected pump in terms of Cable Size, operating Frequency, Number of stages or three Performance criteria: •

Minimum flow rate

•

Best efficiency (operating point)

•

Maximum flow rate

TO OPTIMIZE PUMP PERFORMANCE: 1 Open the Design menu in the Navigator. The ESP Design screen is opened. 2 Open the Optimise tab (see Figure 6‐6).


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Figure 6-7: ESP Design - Optimize Pump Performance

3 Select or enter values for the following fields: •

Pump: The selected Pump, Flow Rate at In‐Situ Conditions (i.e. average Pressure and Temperature across Pump), and Cable Size are displayed at top‐left of the dialog.

•

Cable Size. Select the cable size whose losses are to be included in the Electrical Power in the Optimization results section.

Target: This is used to select the parameter to be optimized on: •

Frequency. This is used to target the pumpʹs performance at a different

frequency to the Designed Frequency. WellFlo will calculate a new Number of stages to allow the pump to produce the same Head at the entered Frequency. •

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Number of stages. This is used to target the pumpʹs performance at an actual Number of stages. The program will calculate a new frequency to allow the Pump to produce the same Head at the entered Number of Stages.



Figure 6-8: ESP Design - Frequency Calculation

where: Voper is the Design Operating Frequency specified in the ESP Data configuration screen ndesign is the Design Number of Stages listed in the Calc column in the Choose ESP for Analysis dialog. fH( ) is the Head Function for the scaled Operating Rate inside the brackets. At convergence, the revised frequency and other optimized parameters will be listed in the Optimization results area. •

Performance. This is used to target the pumpʹs performance at a point on its Performance Curve; the Operating Frequency and Number of stages are recomputed by iteration so that:

— The Pump minimum, maximum or best efficiency value (as selected) corresponds to the target Operating Rate at average Pressure and Temperature across the Pump. — The Pump can produce the required Head at the selected point in the pumpʹs Performance Curve. At convergence, the revised Frequency, Number of stages, and other optimized parameters will be listed in the Optimization Results area. Optimization results: This section displays pertinent data from the previous Optimization calculations: •

Motor Current: This is calculated from:


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Figure 6-9: Motor Current

where: ntarget = the Target Operating Frequency nnameplate = the Motor Nameplate Frequency •

Motor Voltage. The Motor Nameplate Voltage is scaled according to target Operating Frequency:

Figure 6-10: Motor Voltage

•

Motor Power. The Power delivered to the pump.

•

Electrical Power. The total Electrical Power required from surface,

including the losses in the selected cable: Figure 6-11: Electrical Power

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The Cable Voltage Drop includes Temperature Effects on the nominal volts/amp/1000 ft rating.



•

Efficiency. The ratio of the hydraulic work performed by the pump (from

Head and throughput) to the Electrical Power consumed (including the Cable Losses). •

Calc no of stages. The Number of Stages derived from the initial design, or

recomputed for an optimization. •

Max no of stages. The Manufacturer’s maximum recommended Number of Stages for the Pump.

•

Operating frequency. The Operating Frequency specified in the initial design, or recomputed for an optimization.

•

Operating range. This gives the position of the In‐Situ Operating Rate between the Manufacturerʹs recommended Minimum and Maximum In‐Situ Operating Rates (adjusted for the Operating Frequency), as a fraction of the total Minimum‐Maximum Range (0.5 = in the middle). This ignores any adjustments to the Manufacturer’s Minimum/Maximum Flow Rates that may have been entered in the ESP Design screen.

Function Buttons: 4 Click Optimize to optimize the pump according to the current options selected. The data in Optimization results is updated accordingly. 5 After Optimizing an ESP, click Install and return to the ESP Data configuration screen, where the selected pump is displayed with its optimized parameters.


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ESP Vary Depth

VARY DEPTH The Vary Depth screen is used to calculate and display the variation of key ESP parameters with Setting Depth. This option allows users to run the Design criteria against a range of up to 10 Setting Depths. It is best suited to the initial design phase when users wish to find the optimum Setting Depth for the location of the ESP. This Design makes the assumption that no particular ESP has been identified for inclusion in the well, and simply shows the prevailing conditions for the desired pressure boost. Accordingly, no Viscosity Corrections are made, and this should be taken into account when viewing the resultant plot of Total Dynamic Head.

TO VARY ESP DEPTHS: 1 Open the Design menu in the Navigator. The ESP Design screen is opened. 2 Open the Vary Depth tab (see Figure 6‐6).

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ESP Vary Depth

Figure 6-12: Vary ESP Depths

3 Enter up to ten ESP setting depths in the Depths table. You can enter these values manually or have WellFlo calculate and insert them automatically by entering From and to values, then entering the number of Steps and clicking Fill. 4 Click Calculate to perform Nodal Analysis at the selected Depth/s and make the results available for plotting.


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ESP Plotting and Reporting

The calculated results are displayed in the plots. Select from one of the following. •

Pressure/Depth. Plots the Flowing Pressure Profiles for each ESP depth.

•

Gassiness. Plots the Inlet Gassiness for each ESP depth.

•

In‐situ rates. Plots the variation with Setting Depth of the In‐Situ Flow Rates at the Pump Inlet and at the Pump Outlet.

•

Total dynamic head. Plots the estimated Head required at each ESP depth.

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This plot makes no correction for the Viscosity of the Well Product.

Plotting and Reporting 5 Open the Plot tab at the top of the Design screen to view the Pressure/Depth plot or open the Report tab to view the ESP Design report.

REFERENCES 1 Ippen, A.T.: ʺThe Influence of Viscosity on Centrifugal Pump Performanceʺ; Trans. A.S.M.E., Nov. 1964, pp. 823 ‐ 848. EPS would also like to acknowledge the assistance of Reda Pumps in this implementation. 2 Dunbar, C.E.: ʺDetermination of Proper Type Gas Separatorʺ. Reda Tech. Bulletin.

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Chapter 7 GAS LIFT This chapter explains how to configure and design a Gas Lift well model in WellFlo 4.0. Gas Lift Data Configuration ......................................................... 284 Gas Lift Design ............................................................................... 289 Sizing ........................................................................................... 317 True Valve Performance ............................................................ 318 IPO Valves ................................................................................... 320 PPO Valves .................................................................................. 321 Spring‐Operated Valves ............................................................ 323 Orifice Valves .............................................................................. 323 Design Computations ................................................................ 323 Sample Gas‐Lift Plots ................................................................ 326 Order Form ................................................................................. 328 Design Parameters Report ........................................................ 329 Tubing Load Requirements Report ......................................... 330 Design Calculations Report ...................................................... 331 Tubing Requirements Plot ........................................................ 332 References ....................................................................................... 334


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GAS LIFT Gas Lift Data Configuration

GAS LIFT DATA CONFIGURATION The tabular Gas Lift Parameters configuration screen is used to view, enter and edit Gas‐Lift data.

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All options pertaining to Gas-Lift will be disabled if the current software license is not configured for WellFlo/Gas Lift.

Gas‐Lift is modeled in WellFlo by inserting one or more Gas‐Lift Valves in the well system; these are positioned at the bottom of the Tubing components. Gas‐Lift Valves can be declared as Active or Inactive (see “Gas Lift Design” on page 289).

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At least one Active Gas-Lift Valve must be in the model for any Gas-Lift calculations to occur. Gas-Injection into a Flow Line or Riser is described separately and is not part of Gas-Lift Design/Analysis.

Gas‐Lift Valves may be selected by Manufacturer, Model and Port Size from those listed in the gasvalve.csv file. Depending on the selection of Valve Type, either PPO (Production Pressure Operated) valves or IPO (Injection Pressure Operated) valves will be mutually excluded from the valve models that become available.

TO SET GAS LIFT PARAMETERS: 1 Open the Configuration menu in the Navigator. 2 Select the Gas Lift Data configuration screen from the Model Navigator. The Gas Lift Parameters configuration screen is opened in the main content pane (see Figure 7‐1).

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GAS LIFT Gas Lift Data Configuration Figure 7-1: Gas Lift Parameters

3 Insert new rows into the table, as necessary and fill in the following table data: •

Active. The valve status. Check to make the valve Active.

•

Name. A name to describe and identify the valve.

•

MD. The Measured Depth of each Valve in the system. The corresponding TVD field updates automatically.

•

TVD. The True Vertical Depth of each Valve in the system. The

corresponding MD field updates automatically.

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All Valve Depths must be above the Tubing Shoe.

Temp. The temperature at the valve for use when the Manual Temperature Model is selected.


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•

Tro. The Test Rack Opening Pressure for Gas‐Charged and Spring‐Loaded

Valves only.

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For an Orifice Valve, this column is blank.

•

Manufacturer. Select one of the Manufacturers listed, or select None to specify generic valves; the corresponding valve Model field will be automatically updated.

•

Model. Select one of the valve models listed for the specified

Manufacturer or the generic valve. •

Port. Select a port size for the selected Manufacturer and Model.

•

R. R = Apt/Ab. This column displays either the Port‐to‐Bellows Ratio of the selected Port size for an IPO Valve (where Apt is the Port Area), or its complement (R = 1 ‐ Apt/Ab), for a PPO Valve.

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For an Orifice Valve, this column is blank.


GAS LIFT Gas Lift Data Configuration 4 Fill in the following gas lift data: •

Operating pressure. The Operating Pressure.

•

Injection Gas Gravity. The Injection Gas Gravity. This does not need to be the same as the Produced (Solution) Gas Gravity.

•

Valve diff. pressure. The valve differential pressure. This is the quantity by

which Casing Pressure must exceed Tubing Pressure at the valve in order for a valve to open. WellFlo models a Differential Gas Valve assuming a fixed differential. In case several valves could be open by this criterion, only the deepest is assumed to be open. — Use Qgi. Select to enable the Gas Injection Rate field. •

Gas Injection Rate (Qgi). The amount of gas to inject. Either this field or

the alternative GLRi field will be used during calculations and this field is only enabled if the Use Qgi radio button is selected (as described below). Any value entered here will be the base case Gas‐Injection Rate. — Use GLRi. Select to enable the Injection GLR field. •

Injection GLR (GLRi). The Injection Gas/Liquid Ratio value. Either this field or the alternative Qgi field will be used during calculations and this field is only enabled if the Use GLRi radio button is selected (as described below). The value entered here will be the base case Injection GLR.

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If users decide later to select GLRi as a Sensitivity Variable (see “Creating and Editing Sensitivities” on page 218), the Injection GLRs entered there will override this value.

This data is only used if at least one Gas-Lift Valve is specified in the system.


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Deepest Point of Injection: This data is used only if the Analysis mode is Deepest Point of Injection: Operating Point, Deepest Point of Injection: Pressure Drop or Gas‐Lift Design ‐ Valve Positioning, where WellFlo is computing Gas‐Lift Valve depths rather than using specified depths. These fields are used to indicate the Deepest Point in the Well that a Gas‐Lift Valve can be inserted. •

Use Tubing Shoe. When checked, this limits Gas‐Lift Valves to be as deep as the downstream end of the first Tubing Node above the shallowest Active Layer. When unchecked, the Max MD of Injection is used.

•

Maximum MD of injection. Enter the limit on the Measured Depth (MD), for valves in the well. The value must lie between the Wellhead/Xmas Tree and the Tubing Shoe Depth.

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The setting is ignored in Nodal Analysis Operating Point and Nodal Analysis Pressure Drop modes.

In Deepest Injection Point and Gas‐Lift Design modes, WellFlo Analysis is only allowed to position valves above the specified depth. It follows that the default Use Tubing Shoe option allows complete freedom, while Maximum MD of injection applies a depth constraint. 5 Click Apply to save your changes.

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GAS LIFT Gas Lift Design

GAS LIFT DESIGN The Gas Lift Design screen is used to determine the positions of the Unloading Valve/s and Operating Valve to produce the Well at a prescribed Flow Rate for a specified set of Casing and Gas‐Lift conditions, initial static Wellbore Fluid, etc. Any specified Gas‐Lift Valve Depths that may already have been entered via the Gas‐Lift Data configuration screen (see “Gas Lift Data Configuration” on page 284) will be ignored in a Design run.

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The Gas-Lift Valve (GLV) and Electrical Submersible Pump (ESP) Design options are separately licensed within WellFlo; users with a basic WellFlo license will not have access to these. This Design option will be disabled if your Software License is not configured (and activated) for WellFlo/Gas-Lift.

Normally, users will have made a reasonable estimate of the Operating Conditions from an Inflow/Outflow Analysis, using the Deepest Point of Injection: Operating Point option, to identify the optimum Operating Valve Depth and Operating Rate. Users should also have an idea of the range of Valve Depths (i.e. bracketing envelope) that might be required to allow for changing Operating Conditions (i.e. declining Reservoir Pressure, increasing Water‐Cut, Well Stimulation, etc.). This can be achieved by a careful Sensitivity Analysis of all relevant variables. Set‐up the input data as described below, and run the Design option. The Valve Depths will be computed, and the results of the Design Analysis are plotted in the graphing window.

TO ENTER GAS LIFT DESIGN DATA: 1 Open the Design menu in the Navigator. The Gas Lift Design screen is opened in the main content pane (see Figure 7‐2).


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Figure 7-2: Gas Lift Design Panel

Design Options 2 Select Design Options from the menu at the left.

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2a

In the Valve Type group, select the type of unloading valve that will be used in the design as well as the type of valve that will be used for the operating point. WellFlo will then adjust the selection options that are available according to these choices.

2b

In the Unloading Valve group, select the valve model, port size, gas passage correlation and discharge coefficient. These values can either be selected by browsing the catalog as shown in Figure 7‐3 or by loading the default values for these items.


GAS LIFT Gas Lift Design Figure 7-3: Gas Lift Valve Catalog

Default values can be viewed or updated through the Settings menu by navigating to Settings/Options/Default Gas Lift Valves (see Figure 7‐4).


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Figure 7-4: Default Gas Lift Valves

2c

In the Casing Pressure Drop group, select whether to use a casing Pressure Drop at Top Valve (delta P line) and, if appropriate, specify the amount of pressure drop to apply; also, determine whether to use the Constant Casing Pressure Drop method or Ptmax ‐ Ptmin method. If the Constant Casing Pressure Drop method is selected, specify the amount of casing pressure drop to apply or use the value specified in the catalog for each valve. If the Ptmax ‐ Ptmin method is selected, specify the amount of safety factor to apply.

2d

In the Deepest Point of Injection group, specify whether to Use Tubing Shoe as the deepest point of injection; specify the minimum valve spacing to apply to the design; if Use Tubing Shoe is not selected, specify a Maximum MD of injection in the space provided. This data is used only where WellFlo is computing Gas‐Lift valve depths rather than using specified depths. These fields are used to indicate the deepest point in the well that a Gas‐Lift valve can be inserted. — Check Use Tubing Shoe to limit Gas‐Lift valves to be as deep as the downstream end of the first Tubing Node above the shallowest Active Layer. When unchecked, the Max MD of Injection is used. — Enter the limit on the Measured Depth (MD), for valves in the well in the Maximum MD of injection field. The value must lie between the

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Wellhead/Xmas Tree and the Tubing Shoe Depth. — Minimum spacing. The minimum True Vertical Depth (TVD) spacing between Gas‐Lift valve positions to be used in the Design process.

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If the valve spacing is too close, in practice this will lead to unstable Gas-lift.

— Valve diff. pressure. The Valve Differential Pressure. This is the quantity by which Casing Pressure must exceed Tubing Pressure in order for a Gas‐Lift valve to open (i.e. for the Operating Valve to pass the required volume of gas). This value is shared between this screen and the Gas‐Lift Data configuration screen (see “Gas Lift Data Configuration” on page 284). 2e

In the Valve Positioning group, select the numbering method (top to bottom or bottom to top) and a desired amount of round‐off in measured depth for each valve location.

Flow Parameters 3 Select Flow Parameters from the menu at the left. This will bring up the Flow Parameters panel, as shown in Figure 7‐5.


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Figure 7-5: Flow Parameters Panel

3a

In the Design Conditions group, enter the start node information and values for maximum casing head pressure and kickoff pressure. For the Start Node, select the node from which the design calculations are started from the Node Name @ depth drop‐down menu. Users have the choice of starting at the Xmas Tree Node or the Outlet Node. The default is the node used for the last nodal analysis (Pressure drop mode) calculation (if any). Enter the flowing Pressure for the Start Node at which the top‐down computations are to start.

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Enter or edit values for the following gas‐lift input parameters: — Casing head pressure. This value refers to the casing head pressure at which the well will operate after unloading has occurred. It will be computed once the operating valve position has been calculated. — Maximum CH pressure. This value (usually larger than the Casing Head Pressure defined above), is the Casing Head Pressure that users expect to be available at the Wellhead for Gas‐Lift operations, and is required for the Unloading Valve computations. WellFlo reports the optimum Casing Head Pressure that follows from this Maximum Casing Head Pressure value.

i 3b

For the upper-most Unloading Valve, this Maximum Casing Head Pressure value will be superseded by the Kick-Off Pressure value (described below) if this is greater.

In the Design Rates group, select the liquid rate and gas injection rate to use in your design. Rates can either be entered manually, or selected from a performance curve. Select Use Qgi to enable the Gas injection rate field or select Use GLRi to enable the Injection GLR field: — Gas injection rate. The amount of gas to inject. Either this field or the alternative GLRi field will be used during calculations and this field is only enabled if the Use Qgi radio button is selected. Any value entered here will be the base case Gas‐Injection Rate. — Injection GLR. The Injection Gas/Liquid Ratio value. Either this field or the alternative Qgi field will be used during calculations and this field is only enabled if the Use GLRi radio button is selected. The value entered here will be the base case Injection GLR.

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If users decide later to select GLRi as a Sensitivity Variable (see “Creating and Editing Sensitivities” on page 218), the Injection GLRs entered there will override this value.

To select rates from a performance curve, click the Select Rate button. The rate selection interface is launched (see Figure 7‐6).


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Figure 7-6: Design Rate Selection Interface

Once this interface is open, it will display a performance curve showing total liquid production rate v/s gas injection rate (or injection gas to liquid ratio) based on a deepest point of injection analysis. To select a rate to use in your analysis, simply move the cursor over the curve and click the left mouse button at a point of your choosing. Once the rate is selected, WellFlo will generate a confirmation dialog asking you to confirm the rates to use in your design. If you click OK, these rates will be applied to the design conditions (see Figure 7‐7).

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GAS LIFT Gas Lift Design Figure 7-7: Design Rate Confirmation

In some cases, the production engineer may desire to select a design rate based on economic criteria, rather than based purely on well performance. For this reason, an option has been included to allow the user to enter economic information and generate a performance curve based on profitability. To generate such a curve, click the button for profit v/s injection (yellow dollar sign) as shown in Figure 7‐8.


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Figure 7-8: Profit vs. Injection Option

Once this button is selected, an additional Gas Lift Cost dialog appears (see Figure 7‐9), prompting users to select values for oil price, compression cost and water disposal cost. These parameters will be used to perform the economics calculations used in this rate selection method. Figure 7-9: Gas Lift Costs

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After entering the appropriate values, WellFlo generates a new performance curve showing profit v/s gas injection rate (or injection gas to liquid ratio) (see Figure 7‐10). Users can then select design rate in the same manner described above. Figure 7-10: Profit vs. Injection Rate

3c

In the Gradients group, enter values for static fluid gradient or static fluid specific gravity (these items are linked); enter a value for injection gas gravity; and, if you wish to position the top mandrel based on a specified static fluid level, then select the Depth of Static Fluid Level box and enter a corresponding value for static fluid level.


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Enter or edit values for the following gas‐lift input parameters: — Static Fluid Gradient. Enter the Pressure Gradient of the Static Fluid (i.e. Kill Fluid) that is to be unloaded. — Static Fluid Specific Gravity. Enter the Specific Gravity of the Static Fluid (i.e. Kill Fluid) that is to be unloaded.

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These two Static Fluid entry fields are linked for consistency (i.e. editing one updates the other according to the formula: Static Fluid Gradient = Static Fluid Specific Gravity x ρ water /144).

— Injection gas gravity. The Injection Gas Gravity. This value is shared between this screen and the Gas‐Lift Data configuration screen (see “Gas Lift Data Configuration” on page 284); it does not have to be the same value as the Produced Gas Gravity. — Depth of Static Fluid Level (optional). If this value is disabled (i.e. the associated checkbox is unchecked), the Static Fluid Pressure Profile is taken to start at the Producing Wellhead Pressure. This will be the specified Start Node Pressure if the Wellhead is assigned as the Start Node in the Input Parameters section. If the Outlet Node is assigned as the Start Node, WellFlo will use a computed Wellhead Pressure. If this value is enabled (i.e. the associated checkbox is checked), the Static Fluid Pressure Profile for the unloading sequence is taken to start at the Objective Flowing Pressure Gradient at the specified TVD from Reference Depth. This enables a Swab‐Out or other Static Fluid Removal process to be modeled. Figure 7-11: Depth of Static Fluid Level (TVD): 2000

The setting above will start the Static Fluid Gradient at the objective gradient pressure, 2000 ft TVD below the Reference Depth. This will result in a graphical design similar to the one shown in Figure 7‐12.

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GAS LIFT Gas Lift Design Figure 7-12: Design for case where depth of static fluid level (TVD) = 2000 ft.

Figure 7-13: Depth of static fluid level (TVD): 0

The setting above will start the Static Fluid Gradient at the objective pressure gradient at the Reference Depth (i.e. flowing wellhead pressure). This will result in a graphical design similar to the one shown in Figure 7‐14.


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Figure 7-14: Design for case where static fluid level (TVD) = 0.

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The above two examples presume that Wellhead Depth is the same as Reference Depth (e.g. if the Wellhead Depth was 80 ft from the Reference Depth, a Static Level of 180 ft would be 100 ft below the Wellhead). Unloading can be represented against a back-pressure (i.e. flow lines) by entering a negative Depth here (i.e. so the pressure at the Wellhead is greater than zero).

— Injection gas gravity. This value is shared between this screen and the Gas‐Lift Data configuration screen (see “Gas Lift Data Configuration” on page 284); it does not have to be the same value as the Produced Gas Gravity.

Transfer Pressure Margins 4 Select Transfer Pressure Margins from the menu at the left (see Figure 7‐15).

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GAS LIFT Gas Lift Design Figure 7-15: Gas Lift Design - Transfer Pressure Margins

The Transfer Pressure Margins panel is used to specify a number of (optional) Design Safety Factors to be applied during a Gas‐Lift Design; these act to modify the valve transfer pressure that is used to position the gas lift valves and perform the valve sizing calculations. In order to accommodate the various design philosophies used in the industry, WellFlo provides the user with a variety of options for determining transfer pressure bias. 4a

The Bracketing option allows users to space gas lift valves based on the bracketing design methodology. This methodology generates a design line based on a user‐specified error tolerance. This design line is drawn from the wellhead pressure to the target depth of injection at a pressure equal to (1 + error tolerance)*tubing pressure. Users have an option to (a) not use the design line above the bracket, (b) display and use the design line or (c) not display but use the design line. If the user opts to use the design line, unloading valves are then spaced within this design line until the minimum valve spacing is reached. Valves are then evenly spaced until the maximum depth of


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injection is reached. The first valve for which the corresponding transfer pressure (at the valve above) is at or to the left of the objective tubing gradient is considered to be the operating valve. Stations beyond this point or used for extended spacing purposes. These stations can be disabled or retained, depending on whether the engineer wishes to install mandrels at these depths to accommodate future conditions. In addition, the user can overlay a pressure gradient that is reflective of future conditions to better assess how many extended spacing mandrels to use.

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GAS LIFT Gas Lift Design Figure 7-16: Bracketing Options

Figure 7-17: Bracketing Design

4b

Users can determine transfer points by generating a Design Line relative to casing pressure minus tubing pressure. This method is particularly useful in designs for PPO gas lift valves. In this method, a design line is generated extending from a pressure at the surface that is equal to the top node pressure*[1+ (fraction at Xmas Tree)(Pcsg ‐ Ptbg)] to the objective depth of injection at a pressure that is equal to (pressure at depth)*[1+(fraction at Point of Injection)(Pcsg ‐ Ptbg)]. All active gas lift valves are spaced such that their transfer pressures lie on this design line. The operating valve is considered to be the last valve for which the transfer pressure (at the valve above) is at or to the right of the design line. Beyond this point, valves are evenly spaced using the minimum valve spacing until the maximum depth of injection is reached.


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Figure 7-18: Design Line Options

Figure 7-19: Design line based spacing for PPO gas lift valves

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If users prefer, they can select transfer pressures by applying transfer point bias equal to a fixed percentage of tubing pressure at depth. This is done by selecting Transfer Pressures Relative to Ptbg and specifying a fraction or percentage of tubing pressure to apply.


GAS LIFT Gas Lift Design Figure 7-20: Transfer pressure as fraction of tubing pressure at depth

4d

Another method for calculating transfer pressures is to select Transfer Pressures Relative to (Pcasing ‐ Ptubing). This method will select transfer pressures that are shifted by an amount equal to a specified fraction of the difference between casing pressure and tubing pressure at depth. (This is comparable to selecting the Calculate by Depth option in previous versions of WellFlo.) When this option is selected, the following information must be entered: — Fraction at Xmas Tree: (Refer to the underlying note). — Reference Depth: Nominally, this will either be the Tubing Shoe Depth or Maximum Valve Depth. — Fraction at Reference Depth: (Refer to the underlying note).

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The Transfer Pressure at a valve is calculated by shifting the original Tubing Pressure by a fraction of the prevailing Casing-Tubing Pressure Differential at that depth. The Fraction to be applied at each Depth is interpolated between the Xmas Tree/Wellhead and the Reference Depth.

So, at a Valve Depth (z): (Transfer Pressure) = (Original Tubing Pressure) + f(z) x P(z) where, ΔP(z) = Pcsg ‐ Ptbg at Depth (z), and the Fraction f(z) is defined as: Figure 7-21: f(z)r

For the settings illustrated in the example dialog below, at a Valve situated half‐way between the Wellhead and the Reference Depth, the Shift applied would be 35% (i.e. half‐way between 20% and 50%) of the Casing‐Tubing Pressure Differential ΔP(z) at that Depth, and so on for other Valves.


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Figure 7-22: : Transfer pressure as fraction of casing press. - tubing press.r

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The user has a final option for calculating transfer pressure, in which they can shift the transfer points by a User Defined Amount per Station. (This is similar to the method in previous versions of WellFlo where the Calculate by Valve Number option was selected.) When this method is selected, the following entries are required: — Margin at Valve 1 (optional). This is a constant Pressure Shift applied to the objective Tubing Pressure Curve at all Valves, starting at the first Unloading Valve.

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A value between 0 and 50 psi is usual.

(Corrected Tubing Pressure) = (Original Tubing Pressure) + (Transfer Pressure Margin) — Increment per Valve (optional). The Corrected Tubing Pressure (defined above) is given an extra Shift by this increment, at each successive Valve, starting at Valve #2.

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This increment can be positive or negative.

The total corrected Transfer Pressure at the nth Valve is therefore: (Transfer Pressure) = (Original Tubing Pressure) + (Transfer Pressure Margin) + (n‐1) x (Transfer Pressure Increment).

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GAS LIFT Gas Lift Design Figure 7-23: : Transfer pressure based on User Defined Amount per Station

•

Use Exact Maximum MD of Injection. If checked, this option will honor the maximum Measured Depth by inserting an additional Gas‐Lift valve at the maximum depth if the calculations have placed the lower‐most Gas‐Lift valve above this point by relaxing the Design Margin criteria to accommodate the extra Gas‐Lift valve. This will result in a general reduction in the spacing of the unloading valves, but the Minimum Valve Spacing still will be honored.

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This controls the re-positioning of valves for Case 1, described in “Sample Gas-Lift Plots” on page 326. If this checkbox is checked and the Design Operating Valve is one of a group of valves at the Min Valve Spacing, an additional valve is placed below the Max MD of Injection at the Min Valve Spacing. This additional valve is then re-positioned at the maximum depth, and all the higher valves are re-positioned accordingly.

Use Spacing Factor. If this option is left unchecked, the Gas‐Lift Design

calculations will honor the Minimum Valve Spacing and the other Design Margins. This may result in the lower‐most Gas‐Lift valve being placed above the maximum Measured Depth of Injection, which may or may not be considered a problem. Figure 7-24: : Spacing Factor

GLV Calculations 5 Select GLV Calculations from the menu at the left (see Figure 7‐25).


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Figure 7-25: Gas Lift Design - GLV Calculations

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Select an option from the Temperature Correction Calculation Method drop‐down list. This provides the user the option to calculate the temperature correction factors for sizing dome pressure actuated gas lift valves based on one of three methods. These include the following: •

API. This is the method specified in API RP11V6. It applies the ideal gas laws using a number of assumptions. Specifically, the authors of this calculation method assumed a pressure of 1000 psi and a base temperature of 60 degrees F, with nitrogen as the gas in question. This can lead to inaccurate dome pressure calculations, particularly when test rack opening pressures exceed 1000 psi.

•

Winkler-Eads. This method is based on the work of Winkler and Eads, as published in SPE 18871 "Algorithm for More Accurately Predicting Nitrogen-Charged Gas Lift Valve Operation at High Pressures and Temperatures" by



H.W. Winkler and P.T. Eads. This paper presents a correlation that was developed by the authors to provide a more accurate calculation for test rack opening pressure in cases where pressures exceed 1200 psi. •

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Rigorous. This method is consistent with the temperature correction methodology used in prior releases of WellFlo. It rigorously calculates Z factor for nitrogen to determine the precise dome pressure at in situ conditions. It is often desirable to round off the calculated test rack opening pressure by a user-defined amount. This is because it is not practical for gas lift technicians to set valves in the lab to the nearest psi. Realistically, the level of precision that is achievable in practice is the nearest 5 psi at best. For this reason, a value of 5 psi is usual.

Select Use Temperature Bias to use temperature bias to prevent the re‐opening of upper dome pressure actuated gas lift valves.


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Figure 7-26: Temperature Bias Options

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When a gas lift well is shut in, it will typically have a temperature gradient that is significantly less than the flowing temperature gradient. As the well is unloaded, the temperature profile of the well will generally increase until it reaches the flowing temperature gradient. Gas lift engineers often take advantage of this increase in temperature as an additional form of design bias. The idea of temperature bias is to choose set pressures for the upper valves in the well based on a temperature that is less than the flowing temperature. Once the well is unloaded and the flowing temperature profile is reached, the elevated temperature will cause the nitrogen in the bellows of these valves to expand, thus preventing these valves from being re-opened. During the unloading process, the temperatures will be somewhere between the flowing gradient and the static gradient. For this reason, it is advisable that temperatures for the upper valves be based on a “compromise gradient" that is between the static and flowing temperature gradients.

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GAS LIFT Gas Lift Design When the user selects the option PtStatic > PtFlowing, WellFlo uses the following method for determining these temperatures: •

Step 1: Plot the flowing and static temperature gradients.

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Step 2: Locate the depth of the static fluid level in the tubing by constructing a static gradient line from the static bottom hole pressure at depth to the point where it reaches zero pressure.

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Step 3: Locate the first valve below this depth. This is considered to be the first potential operating point in the well. All of the valves above this point will only be used to unload the well and will not be used once the well is flowing.

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Step 4: Construct a ʺcompromise gradient lineʺ from the flowing temperature gradient at the depth of this ʺfirst operating pointʺ to the static temperature at the surface.

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Step 5: Use the ʺcompromise gradient lineʺ to determine the temperatures for all of the valves above the fluid level. These temperatures will be used in calculating the temperature correction factors and test rack opening pressures for these upper valves.

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Step 6: Use the flowing temperature gradient to determine the temperatures for use in calculating the temperature correction factors and test rack opening pressures for each of the valves below the fluid level.

The resulting design will be similar to the one shown in Figure 7‐27.


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Figure 7-27: Graphical gas lift design using temperature bias

When the user selects the option TVD >, the flowing temperature gradient will be used for calculating the set pressures of valves below the specified true vertical depth. For valves above this depth, the compromise temperature gradient will be used.

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GAS LIFT Gas Lift Design 6 If necessary, edit any of the values in the following columns: •

MD. The Measured Depth of each Valve in the system. The corresponding TVD field updates automatically.

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TVD. The True Vertical Depth of each Valve in the system. The corresponding MD field updates automatically.

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Casing Pressure. Displays the Unloading Casing Pressure calculated at this Gas‐Lift Valve.

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Tubing Pressure. Displays the Tubing Pressure calculated at this Gas‐Lift

Valve. •

Temperature. Displays the Temperature at this Gas‐Lift Valve.

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Only Gas-Lift Valves up to and including the Operating Valve have values displayed in the Casing Pressure, Tubing Pressure and Temperature fields. These fields are not editable.

Active. Indicates whether the Gas‐Lift Valve is Active or Inactive.

7 Click Design to perform the Gas‐Lift Design calculations (see “Design Computations” on page 323). WellFlo will delete all the current valves and then calculate the Unloading Sequence and the Steady‐State Casing Head Pressure required to operate the well under normal conditions.

Plotting On completion of the Design computation, a Pressure versus TVD plot is displayed automatically, showing the main features of the Nodal Analysis (see Figure 7‐28). TVD is used to facilitate the plotting of fluid gradients.


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Figure 7-28: Gas Lift Design - TVD Plot

Example plots and their associated input screens are illustrated in “Sample Gas‐Lift Plots” on page 326. 8 Adjust any parameters and click Re-Design to re‐calculate the unloading sequences and pressures for the current valves. This performs a top‐down continuous flow Unloading and Injection calculation using the flow rate and gas‐lift data from the Input Parameters area, and the valve positions displayed in the Gas‐Lift valve data table. It does not re‐compute valve positions.

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This facility enables users to perform "what if..." studies using the valve positions obtained with the Design facility (or the default valve positions specified in the system editor if they have not yet been overwritten with the design results, or a set of user-defined depths) and varying other parameters such as Flow Rate or Maximum Casing Head Pressure.


GAS LIFT Sizing

Sizing Users can adjust valve properties on the Gas‐Lift valve data table, after running the design calculations, to determine valve spacings. Either click into a table cell to activate a drop‐down selection menu, or double‐click in a cell to enter/edit values, as appropriate, to: •

Determine the recommended orifice sizes.

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Compute Opening and Closing pressures for each valve.

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Select either Gas‐Charged, Spring or Orifice valves.

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Compute the required Dome Pressure and Test Rack Opening Pressure for each valve.

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Depending on the valve type selected, the choice of valve models is limited to either: — PPO (Production Pressure Operated) and Orifice valves — IPO (Injection Pressure Operated) and Orifice valves

Port Size Calculation The Port Size can only be selected from the sizes listed in the gasvalve.csv file for the currently selected model. On each port size selection, its associated Discharge Coefficient and Port‐to‐Bellows Ratio are shown as read‐only items. When a change in one of the input columns causes the Port Size to be re‐calculated, the smallest suitable Port Size is selected. When the largest listed Port Size is insufficient for a changed Qgi value, the Qgi that it will actually pass is given. Port sizes are calculated to the nearest 1/64th inch, for the gas flow rate at the valve, at the valve temperature, using the Tubing Transfer Pressure and the Casing Pressure. They are subsequently rounded‐up to the next size listed in the gasvalve.csv file for the selected Manufacturer and Valve Model. The default value of 0.865 is typical for small port sizes, but a smaller value may be more appropriate for larger port sizes.

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If the orifice size is edited and one of the above inputs to its calculation is subsequently altered, it will be re-calculated. The orifice size is not used elsewhere in WellFlo, so users can overtype with the rounded-up sizes required when the calculations are completed, for the purpose of reporting.


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GAS LIFT True Valve Performance

The port sizes are calculated using the Thornhill‐Craver3 equation. •

Port-to-Bellows Ratio (R). R varies with the Port Size and Valve Model as

defined in the gasvalve.csv file. The default (no entry) is 3.142 x (Size/128)2 / Area. •

Discharge Coefficient. Thornhill‐Craver Discharge Coefficient. Default (no entry) = 0.96 if the valve Type is Orifice. Otherwise, the coefficient is 0.865.

•

Criticality Indicator. Shows whether the valve will be in Critical Flow for the given conditions.

True Valve Performance If users have licensed gas lift performance data from the Valve Performance Clearinghouse, they can use True Valve Performance to further refine the sizing of valves within the gas lift design. When users click the True Valve Performance button in the sizing grid, it will launch the True Valve Performance Window, as shown in Figure 7‐29.

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GAS LIFT True Valve Performance Figure 7-29: True Valve Performance

The interface will display a plot of gas passage versus downstream pressure for the corresponding valve, along with opening pressure, closing pressure and tubing pressure at depth. Users can adjust Manufacturer, Valve Model, Port Size Casing Pressure or Tubing Pressure to perform what‐if scenarios for this valve. When the Show Valve Performance Button is pressed, these changes will be applied, updating the calculated TRO, Closing Valve Pressure, R and Qg Max for the valve. The resulting gas passage curve will then be plotted. Once the user is satisfied with the valve performance for the given station, they can press the Accept Selected Valve button, and the changes will be implemented in the sizing grid. If the user chooses not to change the valve selections, they can press the cancel button; and the True Valve Performance window will close, returning them to the sizing grid.


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GAS LIFT IPO Valves

IPO Valves Figure 7-30: Gas Lift Valve Sizing - Injection Pressure Operated (IPO)

Port‐to‐Bellows Ratio (R) varies with the Port Size and Valve Model as defined in the gasvalve.csv file. There are several (differently defined) ratios applied to Gas‐Lift valves; for IPO valves, EPS uses: Figure 7-31: IPO Valve - Port-to-Bellows Ratio

This is typically of the order of 0.1 for IPO valves (i.e. the tubing pressure exerts only a small force via the port, and most of the bellows “feel” the casing pressure. R will vary with both Valve Type (including design, size and materials) and Port Size within a given Valve Type). The Dome Pressures (Pd) can be calculated by two methods. Either method can be assigned to any valve: 1 Use operating Casing Pressure (Pvo): If the Calculated using Closing Pressure column is unchecked for a valve, the operating Casing Pressure (i.e. either a calculated or an edited value) is used along with R and the Tubing Pressure to determine Pd from the Force Balance Equation: Figure 7-32: Force Balance Equation

The Closing Valve Pressure (Pvc) is equal to Pd. The Closing Surface Pressure follows by correcting Pvc for the Gas Gradient.

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GAS LIFT PPO Valves 2 Specify Closing Surface Pressure (Psc): Check the Calculated using Closing Pressure column at the relevant valves and enter the desired Closing Surface Pressures (Psc) for these valves. WellFlo will compute the In‐Situ Casing Pressure (Pvc) from Psc and the Gas Gradient. This is, by definition, the In‐Situ Dome Pressure (Pd). The Operating Casing Pressure (Pvo) at the valve is then calculated from Pd, R and the Tubing Pressure (Pt): Figure 7-33: Operating Casing Pressure

The Opening Surface Pressure (Pso) follows by correcting Pvo for the Gas Gradient. The table now contains the In‐Situ and Opening and Closing Surface Pressures and the Dome Pressure at Valve Temperature. Pd is converted to its value at 600 F (Oilfield Units) and appears in the P dome at 600 F column. Finally, the Test Rack Opening Pressure (TRO) is derived from Pd at 600 F for a Tubing Pressure of 1 Atmosphere: Figure 7-34: Test Rack Opening Pressure (TRO)

The form of this equation depends on the definition of R (as described above).

PPO Valves The methodology is similar to that for IPO valves, with a few important differences: The Design Casing Pressure values are transferred into the Casing Pressure column. The Design Closing Pressures (i.e. objective Tubing Pressures plus Fluid Closing Pressure Margins) appear in the Closing Valve Pressure column; both of these columns can be edited.


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GAS LIFT PPO Valves

Port‐to‐Bellows Ratio (R): R varies with the Port Size and Valve Model as defined in the gasvalve.csv file. There are several (differently defined) ratios applied to Gas‐Lift valves; for PPO valves, EPS uses: Figure 7-35: Port-to-Bellows Ratio - PPO Valves

This is typically of the order of 0.9 for PPO Valves (i.e. the Port Area is small so the casing pressure exerts only a small force, and most of the Bellows Area “feels” the Tubing Fluid Pressure. R will vary with the valve type (including design, size and materials) and the Port Size within a given Valve Type). The Surface Casing Pressure (Pso) is expected to be a constant value, so the default P casing values should be adequate. However, they may be edited if required for each valve. The pressures in the tubing at which the valves are required to close are in the Closing Valve Pressure column; these may also be edited. The required Dome Pressure (Pd) at Valve Temperature is calculated from P casing (Pcsg), Closing Valve Tubing Pressure (Pt) and R using the Force Balance Equation: Figure 7-36: Force Balance Equation

This is listed in the Dome Pressure column. Dome Pressure is converted to 600 F, and appears in the P dome at 600 F column. Finally, the Test Rack Opening Pressure (TRO) is derived from Pd at 600 F for a Tubing Pressure of 1 Atmosphere: Figure 7-37: Test Rack Opening Pressure (TRO)

The form of this equation depends on the definition of R (as described above).

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GAS LIFT Spring-Operated Valves

Spring-Operated Valves Either IPO or PPO valves may be set to Spring‐Operated instead of Gas‐Charged, in the Valve Model column. When this selection is made, dome pressures are still shown, but they are now representative pressures, instead of actual Nitrogen Charge. The Tubing Rack Pressure (TRO) is still the pressure for which the valve should open when the spring has been correctly‐set. There is no Temperature Correction for a Spring‐Operated valve.

Orifice Valves An IPO or PPO valve for which the Calculate by P close column is set to No, may also be set as an Orifice valve in the Valve Model column. Columns that are no longer relevant (i.e. in relation to Opening and Closing conditions) then become blank. For an IPO valve, the Casing Pressure in the P open valve column is initially calculated by adding the valve Differential Pressure from the Gas‐Lift Design ‐ Valve Positioning dialog to the value in the P tubing column. This corresponds to the desired Operating Casing Pressure after Unloading. For a PPO valve, the Casing Pressure is calculated by adding the Valve Differential Pressure to the pressure in the Closing Valve Pressure column. The orifice size required is calculated by the Thornhill‐Craver3 equation, as before.

Design Computations When the Design button is clicked, the following computations are made: 1 The Temperature Profile is calculated according to the Temperature Model selected for Analysis. 2 The objective Tubing Flowing Gradient is computed top‐down from the specified Start Node and Start Node Pressure using the Flow Rate and Gas‐Lift Data entered in the Gas‐Lift Input Parameters area. For this purpose, Gas‐Injection is assumed to be ʺForcedʺ at the specified Maximum Measured Depth (MD) of Injection.


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GAS LIFT Design Computations

3 The depth of the first Unloading Valve is computed from the intersection of the Casing Pressure Profile (which depends on the Injection Gas Gravity) and the Kill Fluid Pressure Profile (at the Static Fluid Pressure Gradient). The Casing Pressure is calculated by starting from the Kick‐Off Pressure (or the Maximum Casing Head Pressure if this is greater), and allows for Frictional Pressure losses at the specified Gas‐Injection Rate. When no Depth of Static Fluid Level has been entered in the Gas‐Lift Design Flow Parameters section (see “Flow Parameters” on page 293), the Kill Fluid Tubing Pressure is calculated starting from the specified Start Node Pressure (i.e. corrected to the Wellhead/Xmas Tree if the Start Node is the Outlet Node). Otherwise, Kill Fluid Tubing Pressure is calculated by starting from corrected Atmospheric Pressure at the specified Depth of Static Fluid Level, if this option has been enabled in the Gas‐Lift Design Flow Parameters section (see “Flow Parameters” on page 293). The depths of the second and subsequent Unloading Valves are calculated in a similar manner, except that: •

The casing pressure is calculated by starting from the specified Maximum Casing Head Pressure instead of the Kick‐Off Pressure, regardless of which is greater.

•

For each valve calculation, the Closing Pressure Design Margin is subtracted from the Casing Pressure at the valve above.

•

For Injection Pressure (Casing) Operated (IPO) valves, the appropriate Transfer Pressure Margin is added to the objective Tubing Pressure. In addition, one Transfer Pressure Increment is added for the third valve computation, and an extra increment is added each time a valve is computed thereafter.

•

For Production Pressure (Tubing) Operated (PPO) valves, the appropriate Fluid Closing Pressure Margin is added to the objective Tubing Pressure. In addition, one Transfer Pressure Increment is added for the third valve computation, and an extra increment is added each time a valve is computed thereafter.

This process continues until WellFlo finds that either: 1 The position of the next unloading valve would be closer than the Minimum Valve Spacing criterion.

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GAS LIFT Design Computations

In this situation, the last valve depth satisfying both the Valve Spacing and the Differential Pressure criteria is marked as the Operating Valve (with all Design Margins). This means that all the declared Design Margins have been accounted for, and the valve depth probably will be pessimistic. WellFlo then continues down hole placing Unloading Valves at the Minimum Valve Spacing until it passes the Maximum Measured Depth of Injection. If permitted (refer to the Use Exact Maximum MD of Injection option in “Transfer Pressure Margins” on page 302), it then re‐positions the deepest valve at the maximum depth, and all the higher valves correspondingly; otherwise, it simply discards the valve below the maximum depth. The Design Operating Valve is marked at the last depth that has enough Differential Pressure (i.e. relative to the uncorrected Tubing Pressure). 2 The Casing Pressure at a projected Valve Depth fails to exceed the Valve Differential Pressure criterion (relative to the uncorrected Tubing Pressure), and therefore could not pass the required Volume of Gas. In this situation, WellFlo will move upwards from the projected position until it reaches a depth where the Valve Differential Pressure criterion is just met (i.e. relative to the uncorrected Tubing Pressure): •

If this position is less than the Minimum Valve Spacing from the valve above, all the overlying valves are moved up proportionately, to give this valve the specified Minimum Valve Spacing from the valve above.

•

This position is now the location of the Design Operating Valve.

If the Design Operating Valve is above the Maximum Measured Depth of Injection, spare valves will be spaced at intervals equal to the Minimum Valve Spacing, down to this maximum depth. Refer to the Use Exact Maximum MD of Injection option in “Transfer Pressure Margins” on page 302. 3 The position of the next valve would be below the Maximum Measured Depth of Injection.


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GAS LIFT Sample Gas-Lift Plots

In this situation, WellFlo will place the Design Operating Valve at the Maximum Measured Depth of Injection, instead of at the calculated position, then move each of the other valves upwards by a proportion of the distance between the Maximum Measured Depth of Injection and the initially calculated position. The Design Operating Valve will satisfy the criteria of Valve Differential Pressure and Minimum Valve Spacing from the valve above, since neither Case 1 nor Case 2 is applicable.

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Gas-Lift valve positions are re-computed each time users click the Design button.

Sample Gas-Lift Plots Figure 7-38: Gas-Lift Design Plot: Pressure versus TVD

The zig‐zag lines show the continuous flow Unloading Sequence, working between the corrected Transfer Pressures (red‐colored circles on left) and the corrected Valve Closing Pressures (green‐colored circles on right).

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GAS LIFT Sample Gas-Lift Plots

The Operating Valve (with all Safety Factors) #7, is positioned at 7,600 ft TVD (horizontal blue‐colored line). This is because of the situation described in Case 1 above; the next valve would, if computed in the same way, lie too close (i.e. within 450 ft) to the valve above it. Figure 7-39: Details of previous Gas-Lift Design Plot

The Operating Casing Pressure Gradient Curve (light green‐colored line) is calculated from the Design Operating Valve Depth to surface, allowing for the appropriate Valve Differential Pressure (i.e. 100 psi in this case), at the Injection Point. All valve depths down to the Maximum Measured Depth of Injection are listed in the Gas‐Lift Valve data table, along with Design Operating Valve Casing Pressures, objective Tubing Pressures, Temperatures and Status (active or inactive) at each valve.

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The Design Operating Valve is the deepest valve marked Active in the Gas-Lift valve data table.


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GAS LIFT Order Form

Order Form After running the Design computations, WellFlo automatically inputs your gas‐lift valve data into a Shop Order form. To complete the Shop Order, fill in the form and save or print it. A sample Shop Order form is displayed in Figure 7‐40. Figure 7-40: Order Form

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GAS LIFT Design Parameters Report

Design Parameters Report After running the design computations, WellFlo generates a Design Parameters Report, which summarizes the input data used in the gas lift design. A sample Design Parameters Report is displayed in Figure 7‐41.


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GAS LIFT Tubing Load Requirements Report

Figure 7-41: Design Parameters Report

Tubing Load Requirements Report After running the design computations, WellFlo generates a Tubing Load Requirements Report which summarizes opening and closing pressure information for the gas lift design. A sample Tubing Load Requirements Report is displayed in Figure 7‐42.

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GAS LIFT Design Calculations Report Figure 7-42: Tubing Load Requirements Report

Design Calculations Report After running the design computations, WellFlo generates a Design Calculations Report which summarizes the sizing calculations for the gas lift design. A sample Design Calculations Report is displayed in Figure 7‐43.


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GAS LIFT Tubing Requirements Plot

Figure 7-43: Design Calculations Report

Tubing Requirements Plot After running the design computations, WellFlo generates a Tubing Requirements Plot which compares the casing closing pressure at depth and tubing pressure required to open the valves with the casing pressure and tubing pressure at depth. A sample Tubing Requirements Plot is displayed in Figure 7‐44.

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GAS LIFT Tubing Requirements Plot Figure 7-44: Tubing Requirements Plot


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GAS LIFT References

REFERENCES 1 Ippen, A.T.: ʺThe Influence of Viscosity on Centrifugal Pump Performanceʺ; Trans. A.S.M.E., Nov. 1964, pp. 823 ‐ 848. eP would also like to acknowledge the assistance of Reda Pumps in this implementation. 2 Dunbar, C.E.: ʺDetermination of Proper Type Gas Separatorʺ. Reda Tech. Bulletin. 3 Cook and Dotterweich: C. of Arts and Industries, Kingsville, Aug 1946. 4 Gas Lift: Book 6 of the Vocational Training Series, from the Production Department, American Petroleum Institute.

334


TUTORIAL 1

Appendix A TUTORIAL 1 The example well is Test1 and the data file Test1.wfl is supplied with the WellFlo installation disks (in the Tutorials folder). The well Test1 is on Gas‐lift and requires a minimum Gas injection before production can kick‐off.

Introduction and Objectives TO VIEW TEST 1.WFLX: 1 Launch WellFlo from its stored location or go to C:\Program Files\Weatherford\WellFlo 4.0 and double‐click WellFlo4.exe to start the program from the default location. The initial WellFlo Getting Started screen is displayed. 2 Go to File > Open. 3 Select Test1.wflx from the WellFlo Tutorials folder (C:\Program Files\Weatherford\WellFlo 4.0\Example). The example well model is opened. Review the various Casing, Tubing and Surface components in the Configuration menu to become more familiar with the system. 4 Select Gas lift Data in the Configuration menu to open the Gas Lift Parameters screen (see Figure A‐1). The Gas Lift Parameters screen has been set up with a base case Injection GLRi of zero. A range of GLRi values will be specified elsewhere for Sensitivity Analysis.


335

TUTORIAL 1 Introduction and Objectives

Figure A-1: Gas Lift Parameters

5 Select Reservoir in the Configuration menu to open the Reservoir Layers Data screen. 6 Open the IPR tab. The IPR plot is displayed (see Figure A‐2). The IPR plot was derived from production test data (i.e. Test data option in the Reservoir Layers Data selection screen). The curvature below the Bubble‐Point (i.e. 5520 psia at 246.9 F) was modeled by the Vogel method, and an AOF of almost 1600 BPD (i.e. 1594.327 STB/day to be exact) total fluid is predicted.

336


TUTORIAL 1 Sensitivity Analysis and Results Figure A-2: IPR Plot

Objectives Owing to the low reservoir pressure, Test1 will not produce without Gas‐lift. A Sensitivity Analysis will be performed to examine the productivity at different Injection GLRs, for different outlet node pressures. The objectives here will be to: •

Ascertain the minimum Injection GLR for production at each pressure

•

Determine the performance curves for the well when producing.

Sensitivity Analysis and Results TO PERFORM A SENSITIVITY ANALYSIS: 1 Open the Analysis menu in the Navigation pane. The Analysis menu is opened to the Operating Conditions screen (see Figure A‐3).


337

TUTORIAL 1 Sensitivity Analysis and Results

Figure A-3: Analysis — Operating Conditions for Test1

The Analysis — Operating Conditions screen is set‐up for calculations at eleven flow rates that have been initialized using the Auto‐Range option. This fills in rates evenly spaced between 5% of AOF and 95% of AOF. 2 Open the Configuration menu in the Model Navigator, and select Temperature Model from the navigation tree. Examining the Temperature Model, the flowing temperature will be calculated at each of the production rates. The model is calibrated against temperatures that were measured at the wellhead and separator while the well was producing at 1332 STB/day (total liquid). Gas in the annulus will be assumed since this is a Gas‐lifted well. 3 Return to the Analysis — Operating Conditions screen by opening the Analysis menu in the Model Navigator.

338


TUTORIAL 1 Sensitivity Analysis and Results The Calculation mode has been set to Operating Point for this study. The inflow calculations will start from the Reservoir (i.e. using the layer pressure of 2171 psia), the outflow calculations from the Outlet node (i.e. base case pressure 96 psia). The Casing has been selected as Solution Node so that the Operating Point pressures computed will be the “Bottom Hole Flowing Pressures.” 4 Select Sensitivities in the Analysis menu. The Analysis menu is opened to the Sensitivities screen (see Figure A‐4). Figure A-4: Analysis — Sensitivities

The Sensitivity 1 variable is the Lift gas/liquid ratio (GLRi), 5 Select Lift gas/liquid ratio in the Manage Sensitivities window to view the Values table. Seven values that have been entered over a wide range from 500 to 3500 SCF/STB with a view to identifying kick‐off. These values will override the base case value specified earlier in the Gas Lift Parameters configuration screen (see “Gas Lift Data Configuration” on page 284).


339

TUTORIAL 1 Plotting

The Sensitivity 2 variable has been chosen as Top/start node pressure, which, in this case, corresponds to the Outlet node. 6 Select Top/start node pressure in the Manage Sensitivities window to view the Values table. Three values have been entered to span a reasonable operating range. These values will override the base case value entered earlier for the Start Node Pressure in the Gas Lift Design screen (see “Gas Lift Design” on page 289). The calculations will be performed using both Sensitivities, making a total of 11*7*3 (= 231) runs, from which a maximum of 7*3 (= 21) operating points could be determined if “stable” intersections were found in all cases. 7 Click Calculate to perform the Sensitivity Analysis.

Plotting TO PLOT SENSITIVITIES: 1 Select Include in Plot in the Analysis menu. 2 Select one or more cases, and click Plot Selected to view their plots. Starting with the Flow Curves tab, separate plots can be produced of the Sensitivity 1 curves and Sensitivity 2 curves versus the first case of the other sensitivity. It is possible to plot versus any (or even all) of the other sensitivity, but for this example, the first case will be used (see Figure A‐5).

340


TUTORIAL 1 Plotting

Figure A-5: Plot for Injection GLR at 50 psia Outlet Pressure

Figure A-6: Plot for Start Node Pressure at Injection GLR = 500 SCF/STB


341

TUTORIAL 1 Plotting

Referring to the Sensitivity 1 Plot in Figure A‐5, note that a Stable Operating Point was identified even at the lowest Injection GLR value. This is for a outlet pressure of 50 psia. The Operating Points for the other two outlet pressures can be read from the Report listing (refer to the sample section of the Report below). In the plot for Sensitivity 2 in Figure A‐6, no intersections occur at all for the 150 psia outlet pressures (i.e. at the Injection GLR of 500 SCF/STB). Although there are two intersections for the 50 and 100 psia cases, one of them is selected as the solution. The operating points for the other six Injection GLRs can be read from the Report listing under the Report tab. 3 For an overall view of the effects of all the values of GLRi and Outlet Pressure on the Production Rate, open the Lift gas/liquid ratio performance tab. The Operating Point Rate can now be plotted for each case against both sensitivities (see Figure A‐7).

342


TUTORIAL 1 Plotting

Figure A-7: Well Performance Plot for Lift-gas GLR

From this plot, it is clear that the Well kicks‐off at a certain minimum Lift‐gas GLR, and that the kick‐off requirement increases with Outlet Pressure. There is no production at 500 SCF/STB, from the well at the highest outlet pressure (150psia). 4 Open the Top/start node pressure performance tab and create the plot shown in Figure A‐8. The plot below illustrates a different way of looking at the same scenario. All the curves show a decline in Production with increasing Top/ Start Node Pressure. All, except the GLRi = 500 curve are able to produce at all pressures.


343

TUTORIAL 1 Plotting

Figure A-8: Well Performance Plot for Outlet Pressure

5 Open the Report tab to view a generated report of the results of all the Sensitivity cases (see Figure A‐9).

344


TUTORIAL 1 Plotting

Figure A-9: Analysis Report

The results can be printed from this report screen or saved to the WellFlo Output section. It is possible to create a Pressure‐Depth Plot for any of the cases. To demonstrate this, the results from Sensitivity Case 14 in the Report can be used. 6 Open the Pressure/Temperature Profile tab. 7 Select the 100 psia Top/Start Node Pressure case and the 2500 scf/STB Lift‐Gas/Liquid Ratio, and click Plot Selected. The Pressure Depth profile is plotted (see Figure A‐10).


345

TUTORIAL 1 Plotting

Figure A-10: Pressure/Temperature Profile

The open Gas‐lift valve at 11506 ft TVD (14695 ft MD RKB) is marked as a solid horizontal line. Since in this case there is sufficient Casing Pressure to open all the valves, the deepest one is opened.

Minimum Gas In order to estimate the minimum GLR requirement more closely, a run should be performed with more closely‐spaced Injection GLR values in Sensitivity 1. A separate run should be made for each of the three Outlet Pressures, so that a narrow range of GLRi can be specified about each approximate kick‐off point. For instance, from the previous Well Performance Plot for Lift‐gas GLR (see Figure A‐7), it was determined that at 100 psia outlet pressure, the well kicks‐off between 0 and 500 scf/STB Lift‐gas/Liquid Ratio. 8 Select Sensitivities in the Analysis menu. 9 Select Lift gas/liquid ratio (Sensitivity 1) in the Manage Sensitivities window, and click Edit.

346


TUTORIAL 1 Plotting

10 Edit Sensitivity 1 to replace the six widely‐spaced values with more closely‐spaced ones (e.g. a Range from 0 to 500 scf/STB in five steps). 11 Change Top/start node pressure (Sensitivity 2) to a single Pressure of 100 psia. 12 Click Calculate to run the analysis and generate the performance curve plot of Operating Rate versus Lift ‐Gas/Liquid Ratio (see Figure A‐11). According to this plot, the kick‐off GLR lies between 200 and 400 scf/STB, with an initial Total Liquid Production Rate of around 980 STB/day.

i

This can be repeated for the other Outlet Pressures.

Figure A-11: Analysis of Minimum Required Lift-Gas/Liquid Ratio


347

TUTORIAL 1 Plotting

348


TUTORIAL 2

Appendix B TUTORIAL 2 The example well is Condens and the data file Condens.wfl is supplied with the WellFlo installation disks (in the Tutorials folder). It is a single‐layer system producing a Gas Condensate fluid.

Introduction TO VIEW CONDENS.WFLX: 1 Launch WellFlo from its stored location or go to C:\Program Files\Weatherford\WellFlo 4.0 and double‐click WellFlo4.exe to start the program from the default location. The initial WellFlo Getting Started screen is displayed. 2 Go to File > Open. 3 Select Condens.wflx from the WellFlo Tutorials folder (C:\Program Files\Weatherford\WellFlo 4.0\Example). The example well model is opened. Review the various Casing, Tubing and Surface components in the Configuration menu to become more familiar with the system.

Condensate Fluid Characterization PVT Tuning From the PVT report, the properties of the produced wellstream were: •

Gas Gravity: 0.700

•

Oil Gravity: 0.785

•

CGR: 105.0 STB/MMscf


349

TUTORIAL 2 Condensate Fluid Characterization

Other properties included a Reservoir Temperature of 230°F and a measured Water/Gas Ratio (WGR) of 150 STB/MMscf. This data was specified in the Reservoir configuration screen. 4 Select Reservoir in the Configuration menu to open the Reservoir Layers Data screen (see Figure B‐1). Figure B-1: Reservoir Layers Data

5 Select Fluid Parameters in the Configuration menu (see Figure B‐1).

350


TUTORIAL 2 Condensate Fluid Characterization Figure B-2: Fluid Parameters

The Equation of State (EoS) model invariably requires tuning before being used in Predictive mode, and this is achieved by entering properties under the Check tab. 6 Return to the Reservoir Configuration menu. 7 Open the IPR tab. The IPR plot is displayed (see Figure B‐3).


351


Figure B-3: IPR Plot

Objectives Owing to the low reservoir pressure, Test1 will not produce without Gas‐lift. A Sensitivity Analysis will be performed to examine the productivity at different Injection GLRs, for different outlet node pressures. The objectives here will be to: •

Ascertain the minimum Injection GLR for production at each pressure

•

Determine the performance curves for the well when producing.

Sensitivity Analysis and Results TO PERFORM A SENSITIVITY ANALYSIS: 1 Open the Analysis menu in the Navigation pane. The Analysis menu is opened to the Operating Conditions screen (see Figure B‐4).

352


TUTORIAL 2 Sensitivity Analysis and Results Figure B-4: Analysis — Operating Conditions for Test1

The Analysis — Operating Conditions screen is set‐up for calculations at eleven flow rates that have been initialized using the Auto‐Range option. This fills in rates evenly spaced between 5% of AOF and 95% of AOF. 2 Open the Configuration menu in the Model Navigator, and select Temperature Model from the navigation tree. Examining the Temperature Model, the flowing temperature will be calculated at each of the production rates. The model is calibrated against temperatures that were measured at the wellhead and separator while the well was producing at 1332 STB/day (total liquid). Gas in the annulus will be assumed since this is a Gas‐lifted well. 3 Return to the Analysis — Operating Conditions screen by opening the Analysis menu in the Model Navigator.


353


The Calculation mode has been set to Operating Point for this study. The inflow calculations will start from the Reservoir (i.e. using the layer pressure of 2171 psia), the outflow calculations from the Outlet node (i.e. base case pressure 96 psia). The Casing has been selected as Solution Node so that the Operating Point pressures computed will be the “Bottom Hole Flowing Pressures.” 4 Select Sensitivities in the Analysis menu. The Analysis menu is opened to the Sensitivities screen (see Figure B‐5). Figure B-5: Analysis — Sensitivities

The Sensitivity 1 variable is the Lift gas/liquid ratio (GLRi), 5 Select Lift gas/liquid ratio in the Manage Sensitivities window to view the Values table. Seven values that have been entered over a wide range from 500 to 3500 SCF/STB with a view to identifying kick‐off. These values will override the base case value specified earlier in the Gas Lift Parameters configuration screen (see “Gas Lift Data Configuration” on page 284).

354


TUTORIAL 2 Plotting

The Sensitivity 2 variable has been chosen as Top/start node pressure, which, in this case, corresponds to the Outlet node. 6 Select Top/start node pressure in the Manage Sensitivities window to view the Values table. Three values have been entered to span a reasonable operating range. These values will override the base case value entered earlier for the Start Node Pressure in the Gas Lift Design screen (see “Gas Lift Design” on page 289). The calculations will be performed using both Sensitivities, making a total of 11*7*3 (= 231) runs, from which a maximum of 7*3 (= 21) operating points could be determined if “stable” intersections were found in all cases. 7 Click Calculate to perform the Sensitivity Analysis.

Plotting TO PLOT SENSITIVITIES: 1 Select Include in Plot in the Analysis menu. 2 Select one or more cases, and click Plot Selected to view their plots. Starting with the Flow Curves tab, separate plots can be produced of the Sensitivity 1 curves and Sensitivity 2 curves versus the first case of the other sensitivity. It is possible to plot versus any (or even all) of the other sensitivity, but for this example, the first case will be used (see Figure B‐6).


355

TUTORIAL 2 Plotting

Figure B-6: Plot for Injection GLR at 50 psia Outlet Pressure

Figure B-7: Plot for Start Node Pressure at Injection GLR = 500 SCF/STB

356


TUTORIAL 2 Plotting

Referring to the Sensitivity 1 Plot in Figure B‐6, note that a Stable Operating Point was identified even at the lowest Injection GLR value. This is for an outlet pressure of 50 psia. The operating points for the other two outlet pressures can be read from the Report listing (refer to the sample section of the Report below). In the plot for Sensitivity 2 in Figure B‐7, no intersections occur at all for the 150 psia outlet pressures (i.e. at the Injection GLR of 500 SCF/STB). Although there are two intersections for the 50 and 100 psia cases, one of them is selected as the solution based. The operating points for the other six Injection GLRs can be read from the Report listing under the Report tab. 3 For an overall view of the effects of all the values of GLRi and Outlet Pressure on the Production Rate, open the Lift gas/liquid ratio performance tab. The Operating Point Rate can now be plotted for each case against both sensitivities (see Figure B‐8).


357

TUTORIAL 2 Plotting

Figure B-8: Well Performance Plot for Lift-gas GLR

From this plot, it is clear that the Well kicks‐off at a certain minimum Lift‐gas GLR, and that the kick‐off requirement increases with Outlet Pressure. There is no production at 500 SCF/STB, from the well at the highest outlet pressure (150psia). 4 Open the Top/start node pressure performance tab and create the plot shown in Figure B‐9. The plot below illustrates a different way of looking at the same scenario. All the curves show a decline in Production with increasing Top/ Start Node Pressure. All, except the GLRi = 500 curve are able to produce at all pressures.

358


TUTORIAL 2 Plotting

Figure B-9: Well Performance Plot for Outlet Pressure

5 Open the Report tab to view a generated report of the results of all the Sensitivity cases (see Figure B‐10).


359

TUTORIAL 2 Plotting

Figure B-10: Analysis Report

The results can be printed from this report screen or saved to the WellFlo Output section. It is possible to create a Pressure‐Depth Plot for any of the cases. To demonstrate this, the results from Sensitivity Case 14 in the Report can be used. 6 Open the Pressure/Temperature Profile tab. 7 Select the 100 psia Top/Start Node Pressure case and the 2500 scf/STB Lift‐Gas/Liquid Ratio, and click Plot Selected. The Pressure Depth profile is plotted (see Figure B‐11).

360


TUTORIAL 2 Plotting

Figure B-11: Pressure/Temperature Profile

The open Gas‐lift valve at 11506 ft TVD (14695 ft MD RKB) is marked as a solid horizontal line. Since in this case there is sufficient Casing Pressure to open all the valves, the deepest one is opened.

Minimum Gas In order to estimate the minimum GLR requirement more closely, a run should be performed with more closely‐spaced Injection GLR values in Sensitivity 1. A separate run should be made for each of the three Outlet Pressures, so that a narrow range of GLRi can be specified about each approximate kick‐off point. For instance, from the previous Well Performance Plot for Lift‐gas GLR (see Figure B‐8), it was determined that at 100 psia outlet pressure, the well kicks‐off between 0 and 500 scf/STB Lift‐gas/Liquid Ratio. 8 Select Sensitivities in the Analysis menu. 9 Select Lift gas/liquid ratio (Sensitivity 1) in the Manage Sensitivities window, and click Edit.


361

TUTORIAL 2 Plotting

10 Edit Sensitivity 1 to replace the six widely‐spaced values with more closely‐spaced ones (e.g. a Range from 0 to 500 scf/STB in five steps). 11 Change Top/start node pressure (Sensitivity 2) to a single Pressure of 100 psia. 12 Click Calculate to run the analysis and generate the performance curve plot of Operating Rate versus Lift ‐Gas/Liquid Ratio (see Figure B‐12). According to this plot, the kick‐off GLR lies between 200 and 400 scf/STB, with an initial Total Liquid Production Rate of around 980 STB/day.

i

This can be repeated for the other Outlet Pressures.

Figure B-12: Analysis of Minimum Required Lift-Gas/Liquid Ratio

362


TUTORIAL 3

Appendix C TUTORIAL 3 This example covers the modeling of the inflow performance for a Horizontal well for both semi‐steady‐state and steady‐state flow. The example well is Horizon and the data file Horizon.wfl is supplied with the WellFlo installation disks (in the Tutorials folder). It is a single‐layer, Black Oil system.

Introduction TO VIEW HORIZON.WFLX: 1 Launch WellFlo from its stored location or go to C:\Program Files\Weatherford\WellFlo 4.0 and double‐click WellFlo4.exe to start the program from the default location. The initial WellFlo Getting Started screen is displayed. 2 Go to File > Open. 3 Select Horizon.wflx from the WellFlo Tutorials folder ( C:\Program Files\Weatherford\WellFlo 4.0\Example). The example well model is opened. The well has a Measured Depth (MD) of 10,000 ft, of which the last 1,000 ft is the horizontal section. The fluid properties used for this well are the default WellFlo values which have not been tuned to the correlations. The Produced GOR is 500 scf/STB and the Water‐Cut is 20%.

Inflow Performance 4 Select Reservoir in the Configuration menu to open the Reservoir Layers Data screen (see Figure C‐1), and check that the appropriate Fluid and Well options are selected for inflow modeling.


363

TUTORIAL 3 Semi-steady State Inflow Performance

Figure C-1: Reservoir Layers Data

In this example, Layer Parameters has been selected as the Entry Model, in conjunction with a horizontal well orientation. Here the Layer Parameters (i.e permeability, pressure, temperature and thickness), are entered as normal.

Semi-steady State Inflow Performance 5 Open the Geometry tab. In this example, the Pseudo-radial flow model (default) has been selected as the drainage area geometry that best describes the reservoir (see Figure C‐2).

364


TUTORIAL 3 Semi-steady State Inflow Performance Figure C-2: Drainage Area Geometry

The Circular shape option has been selected from the Semi‐steady State area. 6 Enter an External radius of 3000 ft and select the Dietz shape factor corresponding to a circle. As the Length (LW) of the open section of this horizontal well is 1000 ft, the use of the Pseudo‐radial flow model is justified. The model has been set‐up to Use calculated skin with an Open Hole completion. The Total Darcy Skin (S) has been calculated as ‐5.111 and that the Productivity Index (J), is 122 STB/day/psi. As the well length is relatively short for this type of well, the Pseudo‐linear model should yield a similar result to the Pseudo‐radial model. 7 To verify this, select the Pseudo-linear flow model. The Pseudo‐linear configurations are shown (see Figure C‐3).


365


Figure C-3: Pseudo-linear Flow Configurations

The Length L1 (7000ft) and Breadth L2 (4000ft) have been set‐up to give approximately the same drainage area (i.e. 2.827e7ft2), as that calculated for the Circular configuration. The Productivity Index (J), is now 119 STB/day/psi, comparable to the 122 STB/day/psi calculated with the Pseudo‐radial model.

i

The Total Non-Darcy Skin (S), for the Pseudo-linear configuration is much higher (i.e. 14.36 as opposed to -5.111 for the Pseudo-Radial Configuration),

The Pseudo‐linear model can also be set‐up with a Square Configuration, in which case the Length L1 and Breadth L2 needs to be altered to 5357 ft (also the Length of Offset = 2178.5ft for L = 1000ft, Breadth Offset = 2678.5ft). This Geometry yields a Productivity Index (J) of 121 STB/day/psi.

366



With this Square Configuration and the Circular Geometry, it is straightforward to do a series of calculations of the Productivity Index (J), to compare the effect of changing the well length on the two models. Such comparative data is shown in Figure C‐4. In all cases, the well was positioned in the center of the reservoir. The Pseudo‐radial data was from the original model with an External Radius (re) of 3000 ft. A comparison was also made in Excel for Reservoir models with a higher anisotropy, with kv/k being 0.01 (i.e. the lower pair of lines on the Plot in Figure C‐4. Figure C-4: Semi-steady State Productivity Indices for Pseudo-radial and Pseudo-linear Geometries

It is clear from the data there comes a point where the Pseudo‐Radial results start to diverge from those of the Pseudo‐linear model, as the well length increases relative to the size of the Reservoir.

i

Note that the divergence starts when the well length is approximately 2000 ft. Note also that the Reservoir anisotropy has a significant effect on the degree of divergence.

As a general rule, the Pseudo‐radial model will be valid if the well length is approximately half the reservoir length or three‐eighths of the reservoir diameter; for longer well lengths, the Pseudo‐linear model should be used.


367


368


INDEX

INDEX

Symbols *.bmp, 24 *.gif, 24 *.jpeg, 24 *.png, 24 *.WFL, 52

A Acceleration Gradient, 235 Advanced Loss Model, 202 Analysis.Log, 242 Analyze Pump, 120 Annular, 62 Application Options, 19 Artificial Lift Method, 61 ASTM, 78

B Back Pressure, 136 Beggs and Brill, 237 Beggs and Brill (modified), 237 Beggs and Brill (no‐slip), 237 Bend, 123 BHP, 224 Black Oil, 63, 75 Bracketing, 303 Bubble‐Point, 85

Bubble‐Point Pressure, 78 Burial Depth, 201

C Calculated Temperature Model, 199 Calibrated Temperature Model, 205 Capacity Modifier, 262 Casing, 105 Absolute Roughness, 106 End Point Measured Depth, 106 External Diameter, 106 Internal Diameter, 106 Segment Length, 106 Start Point Measured Depth, 106 Charts, 21 Choke, 117 Choke Correlation, 69 Choked Fracture, 187 Choked Half‐length, 187 Composite IPR, 154 Condensate, 63, 76 Constant Pressure Boundary, 142 Convergence Skin, 177 Conversions, 32 Corey Exponent, 163 Corpoven Critical Choke Correlation, 241 Coupled Pressure‐Temperature Model, 196 Coupled Temperature Model, 204 Critical Flow, 108

Wellflo | User Guide

369

INDEX

Critical Unloading Rate, 233 Cross‐Flow, 134 Crushed Zone, 172, 178

ESP Data, 256 Export, 224

F D Damage Skin, 169, 177 Data Editor, 23 Data Import Wizard, 25 Deliverability, 14 Depth Conventions, 48 Depth of Static Fluid Level, 299, 300 Design Computations, 323 Design Line, 305 Design Pump, 255 Deviation Skin, 170 Dew‐Point, 85 Dictionary, 33, 35, 37, 40 Downcomer, 125 Downcomer Flow Correlation, 68 Downcomer L‐Factor, 69 Drainage Geometry, 140 Drainage Shape, 142 Circular, 143 Rectangular, 143 Wedge‐Shaped, 144 Dry Gas, 63, 76 Dukler‐Eaton‐Flanigan, 239 Duns and Ros, 236 Duns and Ros (modified), 236

E Effective Shot Density, 188 Efficiency Modifier, 262 Emulsion Viscosity, 81 EPS Mechanistic, 239

370


Fancher and Brown, 238 Fetkovich, 136 Flow Correlations, 65, 229 Flow Parameters, 293 Flow Potential, 14 Flow Regime, 244 Flow Shape Factor, 173, 179 Flow Type, 62 Flowline, 123 Fluid Parameters, 73 Fluid Type, 63, 75 Force Balance Equation, 320 Frac and Pack, 188 Fracture Dimensions, 188 Fracture Face Damage, 187 Fracture Half‐length, 189 Fracture Type, 184 Fracture Width, 189 Fractured, 137 Fractured Interval, 188 Frictional Gradient, 235

G Gas in Annulus, 200 Gas Injection Rate, 126, 287 Gas Lift Parameters, 284 Gas Relative Permeability, 166 Gas Saturation, 166 Gas Specific Gravity, 77 Gas to MD, 200 Gas‐Oil Ratio, 134

INDEX

Gassiness Corrections, 263 Lower Threshold, 263 Upper Threshold, 263 Geothermal Gradient, 200 GLRi, 287 GLV Calculations, 309 Gradients, 299 Gravel Efficiency, 188 Gravel Pack, 171, 179 Gravel Permeability, 188 Gray, 239

L

H

Manual Temperature Model, 198 Medium Temperature, 203 Midperf Depth, 132 Mole Fractions, 80 Motor Wear Factor, 119, 261 Multi‐lingual Support, 33

Hagedorn and Brown, 237 Hagedorn and Brown (modified), 238 Head Factor, 119, 260 Head Modifier, 262 Head per Stage, 263 Heat Transfer Coefficient, 194, 202 Hydrostatic Gradient, 235

I IIR, 137 Increment per Valve, 308 Injection Gas Gravity, 126, 287 Injection GLR, 287 Inorganics, 80 Insulation Conductivity, 203 Insulation Thickness, 203 Interfacial Tension, 234 Intersection Angle, 189 IPO Valves, 320 IPR Model, 135

Languages, 33 L‐Factor, 228 Limited Entry Skin, 169 Limited Height, 187 Logging, 19 Loss Model, 202

M

N Nameplate Rating, 122, 268 Normalized Pseudo Pressure, 136 Normalized Pseudo Pressure External, 136

O Oil API Gravity, 77 Oil Formation Volume Factor, 78 Oil Relative Permeability, 166 Oil Specific Gravity, 77 Operating Conditions, 213 Operating Point, 14, 210 Operating Rating, 122, 268 Operation Frequency, 118, 121, 258 Order Form, 328


371

INDEX

Orifice Valves, 323 Orkiszewski, 238 Outlet Temperature, 205 Output, 47

P p2‐form, 136 Parametric Relative Permeability, 160 Parting Pressure, 134 Perforation, 172, 178 Perforation Skin, 179 Permeability, 132 Pipeline Flow Correlation, 69 Pipeline L‐Factor, 69 Port Size Calculation, 317 Port‐to‐Bellows Ratio, 320 Power Factor, 119, 260 Pressure Drop, 210 Pressure Drop Correlations, 235 Production Rate, 233 Proppant Darcy Properties, 185 Proppant Non‐Darcy Properties, 186 Proppant Permeability, 185 Pseudo‐linear Flow, 142 Pseudo‐radial Flow, 141 Pump Environment, 256 Pump Model, 121, 266 Pump Wear Factor, 119, 260

Q Qgi, 287

372


R Ramey Model, 196 Reference Depths, 71 Relative Injectivity, 132 Relative Permeability 2‐Phase Flow, 158 3‐Phase Flow, 158 Single‐Phase Flow, 159 Reports, 232 Reservoir, 131 Reservoir Layers Data, 131 Restrictions, 107 Rigorous, 311 Riser, 124

S Sensitivities, 220 Separator Efficiency, 120, 261 Shop Order Form, 328 Shot Density, 179 Shot Penetration, 179 Shot Phasing, 179 SI Units, 29 Skin Analysis, 167 Solution GOR, 78 Spacing Factor, 309 Spring‐Operated Valves, 323 Standard Loss Model, 202 Standard Unit, 28 Static Fluid Gradient, 300 Static Fluid Specific Gravity, 300 Steel Conductivity, 203 Straight Line, 135 Sub‐critical Choke L‐Factor, 69 Sub‐Critical Flow, 242 Sub‐Surface Restrictions, 242 Surface Equipment, 115

INDEX

Surface ESP, 118 Surface Temperature, 200 Surface Tension, 79

T Tables, 24 Temperature Bias, 311 Temperature Correction Calculation API, 310 Rigorous, 311 Winkler‐Eads, 310 Temperature Model, 197 Calculated, 194 Calibrated, 196 Coupled, 196 Manual, 194 Terrain Data, 110 Test Point Data, 138 Tide/Wind Speed, 203 Trace Points, 109 Transfer Pressure Margins, 302 True Valve Performance, 318 Tubing, 103 Absolute Roughness, 104 End Point Measured Depth, 104 External Diameter, 104 Flow Configuration, 104 Internal Diameter, 104 Segment Length, 104 Start Point Measured Depth, 104 Tubular, 62 Turner Critical Velocity, 234 Turner Velocity, 233

U Unit, 28 Unit Calculator, 33 Unit Class, 28 Unit System, 28 Units Editor, 27 Unloading Valve, 290

V Valve Diff. Pressure, 293 Valve Positioning, 293 Valve Type, 290 VFP, 224 Viscosity Corrections, 262 Vogel, 135 Volatile Oil, 63, 76

W Water Cut, 134 Water Gravity, 77 Water Relative Permeability, 166 Water Salinity, 77 Water Saturation, 166 Well Orientation, 64 Wellbore Deviation, 96 Wellbore Equipment, 102 Wellbore Radius, 132 Winkler‐Eads, 310


373

INDEX

374


WellFlo User Guide 20090130

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