change of plans: how QEP could optimize returns in their Midland asset in a low-price environment

Should QEP change its development strategy in this lower price environment? Using our machine learning models and Novi software we analyzed QEP’s Midland Asset development plans to determine the best plan going forward.

Based on evaluation of the data, QEP should consider:

• Downsizing completion designs in primary zones.
• Discontinuing development of non-core zones.

How much un-drilled inventory does QEP have in the Midland?

In QEP’s investor decks they outline their 3 core acreage positions that they plan to develop, including their oil well spacing and staking plans. Using Novi we simulated their designs as follows:

• County Line at 33 wells per section.
• Mustang Springs/Robertson Ranch at 40 wells per section.
• Core development design with Lower Spraberry Shale, Wolfcamp A and Wolfcamp B targets at 18 wells per section.

Mapping this out in Novi nets 1,011 gross locations based on their tightest spaced unit designs. We can also review the impact on production of different development timing scenarios. In this example we will run three drilling/development scenarios:

• Permian Total Development: 1 rig program targeting each unit all the way through.
• Permian Infill Development: 1 rig program targeting Lower Spraberry Shale, Wolfcamp A & Wolfcamp B, then returning to drill other zones after main zones have been drilled out
• Permian Core Development: 1 rig program drilling Lower Spraberry Shale, Wolfcamp A and Wolfcamp B.

Novi video – a workflow in Forecast Engine for creating well inventories

What completion designs should QEP test?

After reviewing QEP’s historical completion designs we can see that they have completed the Spraberry formation and Wolfcamp formations differently. We will run Novi predictions on the entire well inventory at these two completion techniques and also on two others, the P90/10 of the other operators in Martin county. In the video below I walk through how we do this within Forecast Engine along with loading in costs and other economic information.

• QEP (Wolfcamp) – 1,800 #/ft of proppant and 1,450 gals/ft of fluid at a $450/lateral foot
• QEP (Spraberry) – 1,500 #/ft of proppant and 1,200 gals/ft of fluid at a $350/lateral foot
• Offset Operators (P90) – 2,250 #/ft of proppant and 2,350 gals/ft of fluid at a $550/lateral foot
• Offset Operators (P10) – 1,050 #/ft of proppant and 1,250 gals/ft of fluid at a $250/lateral foot

Novi video – a workflow in Forecast Engine for creating completion designs

Changing completion design strategies based on the target formation

Comparing the impact of the 4 different completion designs to Novi predicted reserves we can see that the Other Operator P90 Completion case has the largest reserve estimate, going from that case to the Other Operator P10 Completion case case we lose almost ~250 MMBoe in reserves.

However, review of the well EURs demonstrates that using the P90 case increases EURs only by 2-3 bbls/ft with the unintended consequence of significant increases in Novi predicted GOR, a significant downside in today’s market. QEP is optimizing their historical completion designs for maximizing oil in each formation, as you can see from the uplift in oil in the Wolfcamp zones, but the Middle Spraberry would benefit from the design that QEP typically uses in the Wolfcamp.

Optimization strategies for QEP’s Midland asset

If we continue on the path of the QEP Wolfcamp completion what implications does our development plan have on our expected EURs? Reviewing the difference between the 3 different inventories we can see the implications of delayed reservoir development. My colleague did an excellent evaluation of this on the Delaware side in his Co-Develop vs Infill video.

In our Total Development case oil EURs per foot for the 3 core zones show similar production with Infill and Total development scenarios and the other zones only see slight increases to their predictions. Delaying the development becomes a more serious problem when we review what happens to GOR under the different scenarios. Even though oil EUR for the non-core zones does not change the GOR increases significantly when delaying their development. The optimal development for the entire inventory would be to drill and complete all zones within a tighter time frame to maintain oil EURs.

Optimizing NPV for QEP’s Midland asset at different strip prices

Upon final review with prices beginning to drop down to below $30/bbl of oil our future development scenario begins to change. At each price the most economic development case is the Permian Infill Development. QEP should optimize their future drilling schedule to develop units of only the 3 core zones with plans to infill the others later on.

When reviewing that development scenario against the different completion techniques we can begin to see that the Other Operator P10 completion case is the optimal case. At prices today a P10 case becomes more economic and delivers better returns for the inventory.

In the video below we review the outputs and can start to understand what are the drivers of production and what is the best development strategy to go forward with.

Novi video – analysis of production outputs for QEP’s Permian asset

Conclusions

• QEP has 1,011 gross locations based on their widest spaced unit designs .
• QEP is optimizing their historical completion designs for maximizing oil in each core formation.
• Middle Spraberry also might benefit from more of a QEP Wolfcamp completion design.
• The optimal development for the entire inventory would be to drill and complete all 3 core zones and returning later for others.
• At today’s strip a P10 completion case becomes more economic and delivers better returns for the inventory

Analysis like this can be used to further study and drive better business decisions to maximize returns. In my next blog post we will take a look at all the planned DUC wells within the basins to determine the units that can be completed in this price environment and what operators should start to optimize for.

John Chaplin

John Chaplin is a Technical Advisor at Novi where he applies his background in A&D evaluations to ensure Novi's predictive analytics and economics help customers develop better decisions in the field. Prior to Novi, John held various roles in A&D groups at SIPC, Merrill Lynch and Morgan Stanley.