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

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

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

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

Fractured Area

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

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

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

1 month Linear Flow Pressure moves out from fractures Reservoir psi

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

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

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

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

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

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

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

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

Going back to our field example from URTeC Paper 2019-1142 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.

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.

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 2019-1142. The next slide will show an economic comparison of the two designs highlighted here

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

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

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

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

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

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

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