1. SPEGC Northside Study Group “Unconventional Reservoir Horizontal, Multi-Stage Completion Design Optimization”
Presented by
Stephen Schubarth
President
Schubarth Inc
October 22, 2019

2. Optimizing Net Present Value in Horizontal Well Completions in Unconventional Reservoirs
For years attempts at improving completions in unconventional reservoirs (URs) has focused on improving early time producing rates
The EOG 1000 BOE/d club
90 day cumulative production
24 hour Initial Potential (IP)
2019 has seen numerous articles in the WSJ condemning the return on investment the “Shale Operators” have managed, accusing them of chasing initial rate rather than economic return
This presentation will discuss the unique nature of URs and methodologies to focus on economic return rather than IP

3. If you are not looking at a similar plot to these, you are not optimizing for NPV in your completions. The plot on the left shows the optimum stage spacing for a specific stage design and reservoir properties. The plot on the right shows the NPV outcome for both stage designs and number of stages along a specific length lateral and reservoir properties. Similar plots can be made for Return on Investment if desired.
Optimum

4. UR Completion Design Lateral Length Treatment Design
What we can control
What we cannot control
Lateral Length
Treatment Design
Proppant volume & type
Fluid volume & type
# of entry points
Pump Rate
Number of stages pumped
Stage spacing
Formation Properties
Permeability
Porosity*
Water Saturation*
Net Pay*
Reservoir Fluid Properties*
In-situ Stresses
Number of fractures taking proppant
* Determines Hydrocarbons in place per acre

5. Fractured Area

6. Of the things we can control
Only the number of fractures we create has a diminishing incremental hydrocarbon recovery
Increasing Lateral Length & Effective Lf both increase the size of the Fractured Area, thus increasing hydrocarbon recovery proportionally

7. How does production decline in Hz wells?
All Hz Multi-Stage well’s production decline in a similar manner
Early Time Flow
Dependent on the number and length of fracs created and the formation permeability
Transitional Flow
Increased decline rate, beginning dependent on distance between fracs and formation permeability
Late Time Flow
Level and timing is dependent on formation permeability

8. Producing Time = 0 Lateral Length = 10800’ Perm = 500 nD Oil Reservoir
Bo = 1.4 RB/STB
Net Pay = 60 feet
Porosity = 9.1 %
Sw = 30%
Pi = 4200 psi
Pwf = 1200 psi
Lf = 250 feet
108 Fractures
Reservoir
Pressure
psi
2640 feet

9. 1 month Linear Flow Pressure moves out from fractures Reservoir
psi

10. 5 months Pressure Transient interference between fractures begins
Deviation from linear flow
Reservoir
Pressure
psi
Pressure transients between fractures meet

11. 2 years Transitional Flow Depletion of the fractured area Reservoir
Pressure
psi

12. 8 years Entering Late time Linear Flow Fractured area is depleted
Reservoir
Pressure
psi
Fractured area is depleted, flow into fracture area from reservoir

13. Learning from the Past
Previous completion production histories hold the information about reservoir permeability, created effective fracture half-lengths and number of fractures created
Production history matching past wells will unlock these important reservoir and completion properties
If enough production data is available we can determine all three of the above values with a unique match
As long as the production history reaches transitional flow, we can reduce the potential results to a few matches through assuming the number of fractures created per stage
If only the early-time linear flow period is available, there can be no unique match

18. Production History Matching
Over 90% of wells evaluated to date have demonstrated the first two of the flow regions described in the previous slides
Through matching several wells in an area, a range of formation permeability can become determined
If there has been a variance in the treatment volumes among the completions, then a trend of treatment size versus created effective fracture length may also be established
With the knowledge of reservoir permeability and establishing a cost versus effective Lf trend, then optimizing completion design through well economics can be performed

19. The graph shown here depicts the expected production history for a variety of number of created fractures along the lateral
The greater the number of fractures created, the higher the early-time flow rate, however also the earlier the onset of transitional flow
Using these projected flow rates and the knowledge of the cost of each stage the Net Present Value can be calculated for each case and we can determine the optimum number of stages for this reservoir configuration
Reservoir Parameters
Net Pay = 100 feet
Porosity = 10%
Sw = 30%
Perm = 1000 nD
Lf = 150 feet
Pi = 5000 psi
Pwf = 750 psi
Bo = 1.2 RE/STB
Oil Viscosity = 0.5 cps
Lateral Length = 7500 feet
1 Frac/Stage

20. The previous slide shows that increasing stage count increases early time production rates
However, this graph indicates that as stage count increases the incremental oil recovered by the next stage pumped becomes less
Depending on the Discount Factor used in calculating NPV, the early time production increase may not be of much incremental value
In lower permeability reservoirs, there is a greater amount of incremental oil recovered as stage count increases

22. Using the production curves from the previous slide and calculating the incremental NPV between stage counts we can arrive at the graph to the left for a single frac/stage treatment design
If we wish to include variations in treatment size then we must look at the Lf - volume trend established from our history matching
Assumes:
Stage cost = $50,000
Revenue = $50/ barrel of oil
Disc. Factor = 10%/yr
Optimum

23. Going back to our field example from URTeC Paper we find the trends between sand and fluid volumes and effective fracture half-length achieved. From these trends we can establish the volumes (and therefore the cost) of achieving different effective Lf.

24. Fracture treatment costs vary as treatment size varies
Fracture treatment costs vary as treatment size varies. There are both fixed costs and variable costs per stage.
Knowing these relationships allows us to create a graph of stage cost versus effective Lf achieved.

25. Having a model that can create expected production histories for 1000’s of different completion designs, coupled with the knowledge of the cost of each completion design, we can construct an expected NPV graph for achieved Lf and number of stages pumped.
An example of this is shown here for the case history in URTeC Paper
The next slide will show an economic comparison of the two designs highlighted here

26. Reduce Well Cost by $141,000 (-2.5%)
Increase NPV by $1.64 million (+52%)
Increases Drainage Area
Reduces number of wells required to drain land
Reduced well cost despite increased stage cost
Significant increase in NPV
Larger fractured area results in higher oil produced per well

27. Summary
Production behavior in Unconventional Reservoir, Horizontal, multi- stage completions can be described using three primary flow regions
Early-time linear flow
Transient flow period with production levels proportional to the area of the fractures created and the square root of formation permeability
Transitional flow
Depletion of the fractured are which begins when the early-time transients touch
Late-time linear flow
Dominate flow of hydrocarbons from outside the fractured area into the fractured area
The production from these flow regions can be modeled if we know the formation permeability, number of fractures created and the average effective length of the fractures

28. Summary
Production history matching of past wells can provide the unknowns we need to successfully model these completions – Reservoir Character
Over 90% of wells attempted to production history match have demonstrated the behavior necessary to be successful
With the knowledge of reservoir and completion properties successfully evaluated, we can then determine changes to designs to optimize these completion designs based on economics and not just initial production response
To date several formations, from multiple basins, have been evaluated
costs savings averaging a 9% reduction of total well costs have been identified
an average increase of 45% in NPV identified as well

29. Well Spacing
What dictates optimum well spacing? Does well spacing effect Optimum Stage Spacing? What are the primary reasons for Parent/Child production issues?

30. Measure how much oil is recovered by the center well vs. time
Infinite Acting Reservoir
Well Spacing Example:
Effective Lf = 250 feet
Perm = 500 nD
Measure how much oil is recovered by the center well vs. time
Calculate ROI for each well spacing relative to ROI for infinite acting reservoir case
Examine incremental return from decreased well spacing
650’ Well Spacing
350’ Well Spacing

33. Well Spacing What dictates optimum well spacing?
Hydrocarbon-in-place per acre
Effective Lf
Reservoir Permeability
Does well spacing effect Optimum Stage Spacing?
Yes, any reduction in recovery reduces the incremental recovery per stage
What are the primary reasons for Parent/Child production issues?
Effective fracture half-length growing into already depleted intervals

34. Thank you for your time and attention!
Please don’t miss the forest for the trees!! Questions???