whitson⁺ - Nodal Analysis Certification

1. Introduction

Complete the steps outlined below to become a certified whitson⁺ user. It includes performing a nodal analysis workflow for two wells with actual production data from the SPE Data Repository . Those certified have the software skills necessary to complete most nodal analysis and completion evaluation projects in tight unconventionals.

We'll go over two kinds of analyses, typically performed via single point in time estimates from nodal analysis -

1. Running completion design sensitivity tests to prevent a Marcellus dry gas well from liquid loading.
2. Optimizing lift gas injection rate and gas lift design to maximize produced oil rate.

Need help?

Send an e-mail to support@whitson.com.

1.1 Before Starting

Make sure you have watched these three videos in the Getting Started part of the manual (click here).

• 1.1 Login (1 min)
• 1.2 Overview of important basics (3 min 30 sec)
• 1.3 Zoom Plots (3 min)

1.2 Create a Project

1. Go to the Project module in the navigation panel.
2. Click ADD PROJECT up to the right.
3. Name the project "your name - whitson certificate".
4. Click SAVE.
5. All steps are shown in the .gif above.

1.3 Upload Well Data

1. Download the relevant data for the wells →→ here ←←.
2. In the Wells module, click MASS UPLOAD up to the right.
3. Upload relevant data in your project dropping the data file into the MASS UPLOAD frontend.
4. All steps are shown in the .gif above.

Alternatively, all the data required for this exercise has been bundled into a mass upload file, ready to be uploaded, in the Mass Upload -> Examples section.

2. Well 1: Nodal Analysis - Completion Design Sensitivity

SPE-DATA-REPOSITORY-DATASET-1-WELL-37-PHEASANT

We will start with a dry gas well, with little water production. In reality, this is the closest we will get to a "single-phase" flow problem. It is a great place to start the learning curve for unconventional well performance.

2.1 PVT

2.1.1 Reservoir Fluid Composition

1. Go to the PVT module in the navigation panel.
2. Open the Reservoir Fluid Composition Input Card
3. Change the Method from "GOR" to "Dry/wet Gas".
4. Input a Gas Specific Gravity (SG) of 0.6.
5. Click SAVE.
6. Check the predicted fluid composition by clicking the "eye icon".
7. All steps are shown in the .gif above.

2.1.2 PVT Table

1. Go to the PVT TABLE tab.
2. Click EXPORT up to the right.
3. Click EXCEL in the dropdown menu to download the table to excel.
4. We'll not use this table, this is just to show you how this is done.
5. This table represents the PVT that will be used for this well.
   It's done automatically - so just sit back and relax (:
6. All steps are shown in the .gif above.

2.2 Production Data

1. Go to the Production Data module in the navigation panel.
2. Click EDIT up to the right.
3. Change the first measured gauge pressure to 4200 psia.
4. Click SAVE.
5. Does this well have tubing installed?

This section is meant to show you how you can manually edit the production data in case that is needed. In reality, one would not need to edit or delete the production data in most cases.

You can always smooth the data using the SMOOTH button on the top-right to make temporary adjustments to the rate profile.

2.3 Bottomhole Pressure Calculations

2.3.1 View Wellbore Configuration Data

The data for these wells has already been uploaded, so this is just for information.
Potential changes would be made in this view (if any).

1. Go to the Bottomhole Pressure module in the navigation panel.
2. Open the Well Data input card.
3. Plot the (1) Well Deviation survey by clicking the icon next to the "Deviation Survey" text.
4. Click the (2) Well Data tab. Note that the well is currently missing a tubing, so the well is flowing up the casing and accordingly, the flowpath is casing.
5. All steps are shown in the .gif above.
6. Click SAVE.

2.3.2 Calculate bottomhole pressures

1. Click the CALCULATE BOTTOMHOLE PRESSURES button.
   1. This will run the calculation for four different BHP correlations at the same time.
2. Select Woldesemayat and Ghajar as the "Bottomhole pressure to be used in calculations" for simplicity.
   1. The dropdown menu can be found right of the CALCULATE BOTTOMHOLE PRESSURES button.
   2. The selected BHP is used everywhere in the software where BHPs are required (FMB, RTA, numerical model).
3. All steps are shown in the .gif above.

2.3.3 Liquid Loading

1. Click the Liquid Loading tab of the Bottomhole Pressure feature.
   Here, you can compare your actual gas rates to the required critical gas rates to deliver gas through the current wellbore configuration without any liquid loading issues.
2. The critical rate is computed at the end of tubing using the Turner correlation by default.
   You can always change the correlation to use and the depth at which these critical rates are reported for.
3. Does it look like the well is going to be liquid loaded?
   You always want to ensure that the actual gas rates from the well are higher than this crtical rate - this is a commonly used diagnostic for gas wells.

2.4 Nodal Analysis

2.4.1 Create an IPR and VLP

Step 1:

Navigate to the Nodal Analysis section.

Select the Bottomhole Pressure (same as above, Woldesemayat and Ghajar) and IPR type - Gas wells default to the C & n IPR or the backpressure equation while oil wells will default to using the Vogel IPR.

Step 2:

Choose a date to create an IPR, VLP curve for - for this case, we'll choose the most recent date which is also the default selection for generating an IPR.

This automatically pulls the bottomhole pressure, reservoir pressure, gas/liquid rate and the wellbore configuration in use for the chosen date.

For the reservoir pressure, you have the following options for the source of the average reservoir pressure for the chosen date:

1. Multiphase Flowing Material Balance (MFMB) or dry gas FMB,
2. Numerical model history match If none of these analyses have been performed, the initial reservoir pressure is used by default.
   

In this case, we'll just skip the additional analyses and work with default - the initial reservoir pressure of 4450 psia.

Step 3:

Click the Create VLP button on the top-left of the page. This generates the VLP, with solid and/or dotted lines, where, the dotted section of the VLP indicates the operating conditions with the configuration in use that will cause liquid loading in the well, based on the critical rates.

The operating point (given by the intersection of the IPR and VLP from the wellbore configuration on the chosen date) is represented with a black marker, this represents the current gas rate and bottomhole pressure deliverable by the configuration in use, as of the chosen date.

This shows that we're nearly at the point where the well will quickly start liquid loading if we continue producing it via the casing. Can we prevent this by simply lowering the casing pressure of this well or is it about time we consider installing tubing? Let's find out!

2.4.2 Add a new wellbore configuration/case

1. You can add a new wellbore configuration by clicking the Edit icon next to the New Well Configuration section in the input panel to the left.
2. Here you can either add a completely new configuration (typically tubing, or artificial lift or both) and just enter the update the surface pressures and/or artificial lift parameters (such as lift gas injection rate, pump intake pressures, etc - relevant options will be available depending on the new well configuration in chosen).

1. For our first test, let's see the effects of lowering the casing pressure. No need for any changes to the configuration, just enter a lower casing head pressure of 200 psia as shown above.
2. Click the Create VLP button again - now, the VLP from your configuration in use will be plotted as VLP (Current) and the VLP from your new well configuration will be plotted as VLP (New).

Note how the intersection between the IPR and VLP shifts, representing a higher well deliverability in terms of gas rates with bottomhole pressure lowered further. This also delays liquid loading significantly because the new VLP is liquid loaded at much lower gas rates, down to about 3 MMscf/D or lower.

2.4.3 Save VLP cases

1. Click the Save Case button to save the current VLP (New) such that you can replot this without having to make all the adjustments made to generate the VLP.
2. Give this case an appropriate name. Let's call this one "CasingFlow - 200 psia CHP".
3. You can click the Show checkbox next to each saved case to include or exclude it in the plot - this should let you compare multiple cases against the VLP (Current).
4. The adjustments made to generate the VLP in terms of the configuration and other input parameters can be viewed by clicking the three dots off to the right of each saved case and selecting View Case in this menu.

2.4.4 Test alternate operating strategies

Instead of lowering the casing head pressure, what if we installed tubing in the well?

To run such a comparison, we need to repeat the steps above - each time changing the new well configuration, entering the relevant wellhead pressure and other input and saving these cases.

Let's build 2 additional saved cases to compare installing tubing vs lowering casing head pressure -

Case 2: Add a new well configuration - Add tubing to the configuration

You can use the tubing tables to add 2 7/8", 6.4 ppf tubing OD and ID upto 6500 ft (Tubing depth in MD) and choose the "Tubing" flowpath. Use a tubing head pressure of 967.95 psia and click Create VLP. Save this case as "2-7/8in TBG - 967 psia THP"

Case 3: Add a new well configuration - Let's try a different tubing size

You can use the tubing tables to add 2 3/8", 4.6 ppf tubing OD and ID upto 6500 ft (Tubing depth in MD) and choose the "Tubing" flowpath. Use a tubing head pressure of 967.95 psia and click Create VLP. Save this case as "2-3/8in TBG - 967 psia THP".

Notice how the smaller tubing has a higher frictional pressure drop so it results in slightly lower rate, increased BHP but much more delayed liquid loading.

Note that since we added tubing to the configuration and the flow is up the tubing, the casing pressure used is no longer relevant to the VLP and only the tubing pressure will make a difference. For the purpose of continuity, the tubing pressure used above is the casing pressure that the well was being produced with, on that chosen date.

All the steps are shown in the GIFs above.

2.4.5 Conclude

We used nodal analysis to see if this gas well can be prevented from liquid loading in the near future by adjusting the operating conditions. To compare all these cases, click the checkbox to include them all in the same plot:

You can reset the VLP by copying the current configuration and reselecting the date to pull input information again as shown in the GIF above.

Bonus questions

1. Which operating conditions offer the highest incremental rate? Does this prevent liquid loading?
2. Which configuration would you pick to sustainably prevent liquid loading for the longest time and why?

You can include these answers along with your certificate project submission below.

3. Well 2: Nodal Analysis - Gas Lift Optimizer

SPE-DATA-REPOSITORY-DATASET-1-WELL-2-HAWK

This is an Eagleford black oil well. The preliminary steps to conduct this analysis include initializing PVT, updating the wellbore configurations to include gas lift valve details, and calculating BHP and viewing gas injection depths vs time.

The rest of the workflow involves using Nodal analysis and specifically the gas lift optimizer, where we will examine the effects of altering gas lift injection rate on produced oil and see the optimal gas injection rate to maximize the same. We will also conduct a lookback by picking a date when the gas lift injection was much lower than this optimum - to see potential upside of increasing the lift rate sooner.

3.1 PVT

1. Navigate to the PVT section and click the edit icon on the Reservoir Fluid Composition card. Note that the initial GOR was preloaded from the mass upload for this well.
2. Click Save. This generates the fluid composition and the relevant black oil tables.

3.2 Bottomhole Pressure Calculations

3.2.1 Correcting Wellbore Configurations - Adding valve details

1. Go to the Bottomhole Pressure module in the navigation panel.
2. Open the Well Data input card.
3. Click the (2) Well Data tab. Note that there is only one configuration here since the gas lift calculation is only activated for the days when there are gas lift injection rates in the data. For the days that do not have gas lift rates, the BHP calculation simply assumes tubing flow with no artificial lift.
   Choose 'Valves' for 'Gas Lift Configuration' and click the edit icon to enter the valve details (depths, opening and closing pressures) as follows:

Valve MD (ft)	PSO (psia)	PSC (psia)
1500	1158	982
3000	1120	950
5000	1060	870
7000	1015	834

Click Save to save the valve details and click the Save button again to save this wellbore configuration. All these steps are shown in the GIF above.

3.2.2 Calculate BHP and view gas injection depths

1. Click the CALCULATE BOTTOMHOLE PRESSURES button.
   1. This will run the calculation for four different BHP correlations at the same time. For gas lift wells, this also calculates the operating valve (i.e. the valve that the lift gas is injected into - depending on the casing and tubing pressures) for the gas lifted portion of the well history.
2. Select Woldesemayat and Ghajar as the "Bottomhole pressure to be used in calculations" for simplicity.
   1. The dropdown menu can be found right of the CALCULATE BOTTOMHOLE PRESSURES button.
   2. The selected BHP is used everywhere in the software where BHPs are required (FMB, RTA, numerical model).
3. Click the Gas Lift Plot to view the gas injection depths vs time for the given gas lift design - just double-click the 'Gas-Lift Valve Depth' in the plot legend to isolate this data on the plot. You can also enable gas lift valve depths to see where the installed valves are located in the wellbore.

Notice how the gas lift is injecting shallow at the beginning and eventually injects into the deepest valve at later time with increased rates so there might be potential for further optimization.

3.3 Optimizing Gas lift Rates

Why optimize gas lift?

Gas lift is a useful form of artificial lift that works by primarily lowering the hydrostatic gradient in the wellbore - this reduces the BHP and allows more fluids to be drawn into the wellbore and hence produced.

Optimization of a gas lifted well may involve changing gas injection rate, pressure, etc. to control the gas injection depth in the wellbore and hence reduction in the bottomhole pressure. The most optimized design injects as deep as possible into the wellbore and yields the maximum reduction in bottomhole pressure.

A diminishing return can be anticipated when the design parameters are pushed to inject more gas into the wellbore. The gas injected in excess of this optimal limit has a higher frictional pressure drop in the wellbore, which in turn, yields a higher bttomhole pressure and reduces the production rate.

3.4.1 Step 1: Nodal Analysis

1. Navigate to Nodal Analysis.
2. Choose the most recent date - that should be selected by default, which pulls in the current gas lift configuration in place and the associated pressures, rates available.
3. Click create VLP button.
4. This gives you the current operating point for the gas-lift rate on that day.

We could update the gas-lift rate, recreate the VLP, save the case and repeat these steps recursively here to find the most optimal gas-lift injection rate that lowers the BHP and maximizes the produced liquid rates. Instead, we'll skip this sensitivity analysis and directly use the Gas lift Optimizer (which does this for you) below.

3.4.2 Step 2: Gradient Calculator

Why does pressure vs MD look counter-intuitive?

To answer this question, we need to take a look at the deviation survey to see the toe and the heel of the lateral:

The well construction is toe-up, such that the toe of the lateral is shallower than the heel of the well lateral. This creates a lower pressure at the toe and higher pressure at the heel which causes this shape in pressure vs MD.

3.4.3 Step 3: Gas Lift Opt

1. Switch over to the Gas Lift Opt tab on the top.
2. This plot shows you the oil rate yield curve, where the incremental oil recovery with incremental increase in gas injection rate can be plotted based on the IPR/VLP for that chosen date.
3. The plot shows the current operating point with an X marker and the most optimal operating conditions with the circle marker. The curve itself shows that the oil recovery reduces with an increase in gas lift rate beyond the optimal point.
4. You can add additional cases by clicking MODIFY CASES to adjust parameters such as tubing and casing pressure. This also allows for the option to modify the wellbore configuration to generate the gas lift optimization curve for alternate strategies (such as injecting via the tubing or modified gas lift valve depths)

Notice that this analysis recommends increasing the gas injection rate by ~740 Mscf/D to about 956 Mscf/D to produce an additional 41.5 STB/D. This additional recovery can be achieved, at times with minor modifications to gas lift wells.

On the flip side, we can also see the impact turning off gas lift - the point where the curve intersects the y-axis (lift gas injection rate = 0) represents the achievable oil rates with the same wellbore configuration if the gas injection was completely turned off. From the plot here, we can see that the well would still make 330 STB/D with no lift-gas injection!

3.5 Lookback - When the gas lift rate was lower

1. Navigate back to IPR/VLP tab and add a new scenario, let's call it "YourName - Lookback"
2. Pick 25th February 2021 (or day 56 in the well history) to calculate the IPR and VLP for that date - The reason we choose this date for a lookback is because we were injecting much lower gas-lift rates. We also know the gas injection depth for this part of the well history is shallower than the later part of well history from the bottomhole pressure section, so there should be a much higher margin for optimization.
3. Click on Create VLP for this case. The resulting intersection shows much higher bottomhole pressure and lower rates, indicating the lower efficiency.

Creating a scenario in whitson⁺

When you click on "Add a new scenario" from anywhere in the software (Dropdown right up top or the Scenarios page), you take the current scenario you are on (i.e.all the analyses/interpretation/input you have in there) and create a copy. All scenarios refer to the production data in the 'Main' scenario - so you will not be allowed to edit the production data from any of the scenarios (other than 'Main') - but you can edit all other input (including smoothing on the production data) without affecting any other scenario.

Another pro-tip: If you want to create a copy of a particular scenario, first navigate to that scenario (by clicking on it from the dropdown) and then click the "Add scenario" button then. Creating a scenario always copies everything from the scenario it is created from.

Let's run the gradient calculator for this case to confirm that this gas lift injection rate yields a much higher bottomhole pressure:

1. Navigate to the Gradient Calculator tab on top.
2. Under the list of Gradient Cases, Click the Modify Cases button off to the right.
3. Here, instead of replacing the case we originally set up for the most recent date, we'll add a case here, let's call it "Lookback" and use the date picker in the table to select day 56 and pull all the associated values required for the table. Click SAVE.
4. Automatically, your new case should be running and you should be able to see the results on the plots below these cases.

You see that the bottomhole pressure for the lookback case shows much higher bottomhole pressure at TVD compared to the most recent case. Is the pressure gradient (psi/ft) in the wellbore higher or lower for the new case we just added above?

Next, we'll run the gas lift optimizer for this date, steps shown in the GIF above:

1. Navigate to the Gas Lift Opt tab on top.
2. Click "Fetch Values from the IPR". This ensures that the gas lift optimizer is using the appropriate data as in the IPR/VLP section.
3. Notice how an orange exclamation mark appears next to the case? This indicates that the input has changed so the results are outdated. Click RUN.
4. This should regenerate the gas lift optimization curve and replaces the warning sign with a green check mark. Time to look at the results!

It shows that the margin for improvement is much higher. If we increased the lift gas injection rate to 1232 Mscf/D, we have the potential to recover about 1161 STB/D instead of the 935 STB/D in oil rates - this is an increase of almost 230 STB/D! The gas lift optimization curve also shows that the lift gas injection rate used on this date is barely effective - turning it down all the way to 0 Mscf/D, still allows the well to deliver about 910 STB/D.

3.4 Conclude

This clearly outlines the benefits of using Nodal Analysis - specifically the gradient calculator and the gas lift optimizer, in this case to improve the lift efficiencies and test alternate strategies of lift gas injection rate and pressure combinations to optimize the well deliverability.

Such analyses are invaluable to all producing wells, so we can operate them at much higher efficiency.

Bonus questions

1. If we did not have the additional gas available to inject, how would you use nodal analysis to prove that you can produce the same rate uplift without changing the current gas injection rate? What would you prefer to change in this configuration?

2. Can you prove your plan with a quick gas lift optimization calculation?

4. Done?

When you are done with your analyses, please:

1. Send an e-mail to certification@whitson.com
2. Make the subject: "whitson⁺ Nodal Analysis certificate: [YOUR NAME HERE]".
3. Include the link to your project.
4. If you have any notes, comments, or observations related to the exercise, feel free to share them with us. Also feedback on the user friendliness of the software is always appreciated.

After that, we'll provide some feedback on your evaluation and issue your whitson⁺ certificate if all looks good.

Cheers and Congratulations!