Primary Vision Insights – July 27th 2022

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As we get to the dog days of summer, we thought it would be important to review where U.S. completion activity has been and where it is going for the rest of the year.

Last year we did a deep dive, highlighting how there was going to be a ceiling to activity with equipment shortfalls pervasive in the market. When we review horsepower, there are about 325 usable spreads in the U.S., with the last 15 being far below “optimal,” but could be used for some shallow or less intense work. I know we will be preaching to the choir when we highlight how supply chains, logistics, and costs have hindered the build-out or repair of equipment. In 2020, spreads were dropping like flies as companies rushed to warm and cold stack horsepower as best they could, but through cost cutting and the bite of mother nature, available capacity was cut drastically. There have also been some technological improvements in the refrac space that revitalize wells and can help bolster corporate returns while delivering more product to market.

There are currently 285 spreads operating in the U.S., and we think 300 completion crews will be active by the first week of August. There will be some flexibility higher, but it won’t be maintained for long as the swing capacity will be in smaller basins. Many of the large drivers (such as the Permian and Eagle Ford) are reaching maximum utilization, while the loss of Freeport LNG caps total natural gas basin activity in the near term. The price of hydrocarbons, current spreads, and available storage capacity support our view that we will have an exit rate of 12.2M barrels per day with additional upside to natural gas and NGL production. Pricing in the market will stay accretive due to a limited supply response and the “miles per ton” of cargoes increasing as Russia sends more product to Asia (India and China). As Russian flows remain limited, Europe is pulling harder on the LNG market, shifting demand structures as Central Asia and Emerging Markets in general struggle to source natural gas. This is moving them down the cost curve from LNG to diesel, and some even further down to high sulfur fuel oil. The middle distillate market remains highly competitive as global storage levels are either at or near all-time lows. The shortages are keeping the natural gas liquids market well bid—especially LPG (liquid petroleum gas), which is keeping U.S exports at a record-breaking pace. We are in a unique position to fill the growing demand for LPG and LNG as countries address pollution concerns and find long-term solutions. We believe these aren’t “bridge fuels,” but rather long-term solutions to a viable basket approach of “green technology” regarding electric generation, industrial power, and consumer consumption.

I always joke that the U.S. is great at two things: arbitrage and inventing things. When you look at the energy market, arbitrage opportunities abound, but we need to revisit some old technology and find ways to improve it. Refracs have answered the call with more opportunity across the U.S., and not just in the case study we did in the Eagle Ford. (We will soon have follow-up studies with the Permian and Haynesville.) You may be asking, What is a refrac? It is when a completion spread comes in to “Re-stimulate” the well by fracturing it again with a mixture of proppant, fluid, and chemicals. Because the well was already producing, the company can use existing infrastructure, helping to limit costs and maximize returns. We will highlight some of the new techniques in greater detail below, but the footnotes are: sustainable step ups in EURs provide a spike in production and total flows move up and to the right. We can come in and use tighter cluster spacing to increase the total return factor, or said more simply: total recovery moves up. So an E&P will have the ability to capture higher prices without worrying about DUCs (drilled but uncompleted wells), drilling new wells, or completing a new well with additional costs. There is a bit less pressure on the supply chain as the need for new casing (vertical section), tubing, pumps, and surface facilities for each well is not necessary. Refracs are also a more sustainable process for ESG goals and capital allocation.

We have all seen articles that list 100M barrels a day of oil consumption, but it is important to make a distinction about that key number. Liquids is almost 40% of that number, and we believe that will be the biggest growth driver of the next decade. For example: even during COVID, India only saw one month of depressed LPG demand. Petrochemical facilities are being built around the world to meet the growing plastic demand, which EVs and green technology need a significant amount of to properly operate. U.S. shale produces a much lighter cut of crude and heavy natural gas that can be split into its different components. Refracs (depending on location) typically yield a higher cut of liquids and natural gas, which in the past was a detriment. But now, as NGLs, naphtha (condensate), and natural gas see more global adoption, the “pie” (or demand) is going to continue rising.

As we dig in on refracs in the Eagle Ford condensate window, the maximum recovery factor (based on MCFE) observed from the most efficient completions is in the 35% range. The combined recovery factor was calculated from the combination of the pre-refrac cumulative production plus the post refrac EUR. The ESG benefits and ability to support our Allies opens up a plethora of opportunities for the White House to promote this as a viable solution. It helps them save face on the ESG front while generating real returns and filling a growing void in the market.

Organic shale refracs work primarily due to rock that was initially unstimulated, leading to poor productivity. In SPE 174994 (Barba 2015) a comparison was done between core “as received” permeability and the permeability from a diagnostic fracture injection test (DFIT) on the cored interval. [1] The “as received” value was 14 nanodarcies (a unit of permeability) and the post DFIT value was 27,000 nanodarcies (or 0.027 md). This suggests that the rock can be stimulated to produce, and there is minimal contribution from the unstimulated portions. This hypothesis was supported by a field experiment done by ConocoPhillips in the Eagle Ford (White 2018) where a horizontal pressure monitor well was drilled 70 ft away from an existing producer that had been frac’ed several years earlier. [2] The pressure gauges and underlying data indicated that only 7.5 ft of lateral interval had any pressure depletion and that 85% of the 50 ft cluster spacing had stranded hydrocarbons. Until mid-2016, the majority of organic shale completions had cluster spacings over 50 ft. In the Eagle Ford alone, there are over 13,000 wells that utilized these wider spacings. There are other areas that also fall into this category: the Haynesville, with over 3000 wells, and the Permian Basin, with over 4500 wells. The expected recovery factor of a 50 ft cluster spacings is 3.5% (Xiong et al 2020) assuming a 60% cluster efficiency without the use of Extreme Limited Entry (XLE). [3] The new entry was not implemented in the industry until 2018 after all these wide cluster spacing wells were completed (Weddle et al 2018). [4] By using XLE, the P50 post refrac expected recovery factor in the Eagle Ford oil window and Permian is 13.7% or 3.9 times the expected recovery from a 60% cluster efficiency wide cluster spacing completion (Barba and Villarreal 2020).

[1] Barba, Robert : “Liquids Rich Organic Shale Recovery Factor Applications,” SPE paper 174994 presented at the 2015 SPE Annual Technical Conference and Exhibition, Houston Sept 28-30.

[2] White, Matt presentation at the 2018 SPE/Icota Workshop: Refracturing Through Optimized Interventions, San Antonio, Texas 9-10 October (not published)

[3] Xiong, Hongjie et al: “The Effective Cluster Spacing Plays the Vital Role in Unconventional Reservoir Development – Permian Basin Case Studies,” SPE-199721 presented at the SPE Hydraulic Fracturing Technology Conference and Exhibition held in The Woodlands, Texas, USA, 4-6 February 2020

[4] Paul Weddle, Larry Griffin, and Mark Pearson: “Mining the Bakken II: Pushing the Envelope with Extreme Limited Entry Perforating,” SPE paper 189880 presented at the 2018 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, 23-25 January

The economics of tighter spacing can be demonstrated with a case study from the Eagle Ford where the recovery factors for the initial wide cluster spacing completion is compared to post refrac (Barba et al 2022). The change in the production profile of the well is shown below in Figure 1.

In the above chart, the initial frac was done in June 2014 with 67 ft cluster spacing, 776 lb/ft of proppant loading, and 17 bbl/ft of fluid. The ultimate recovery of the initial frac was estimated at 97,613 BO with a negative $2.2 million net present value (NPV), assuming a $6 million authorization for expenditure (AFE) for a new well. These economics assume the following prices: $93.63 oil and $5.59 gas for 2022, $83.59/$4.45 for 2023, and flat $77.28/$3.77 for 2024 and beyond. Comparison of this volume to the petrophysical oil in place (Figure 2 below) indicates the initial frac would only recover 3.0% of the oil in place. This compares to the predicted recovery factor from the work done by Hongjie Xiong where the range is from 2.2% for 60% cluster efficiency to 4.5% for 100% cluster efficiency. When only the stimulated rock volume is producing, the recovery of wide cluster spacing has physical limits driven by the relatively narrow slices of stimulated reservoir volume (SRV) generated at each cluster (7.5 ft per the Conoco study).

The sample well we are discussing was revisited in July 2016 when a “bullhead” frac was conducted through the existing perforations with 445 lb/ft of proppant and 11 BBL/ft of fluid, which resulted in an increase from 3% to 3.8% in the total recovery. In December 2017, the well was mechanically isolated with a 4-inch cemented liner and reperforated with 17 ft cluster spacing. With mechanical isolation, the refrac design is the same as a new well, with the only difference being higher friction pressure due to smaller diameter tubulars. This limitation can be offset with the use of expandable tubulars, which, in this case, was 4.1-inch vs 3.4 inch for the 4-inch cemented liner. The higher friction pressures can also be reduced using larger perforations in each cluster (Gabin et al 2021). The larger holes in that study resulted in lower breakdown pressures, lower near wellbore tortuosity, and less perforation erosion.

In Dec ‘17, the well was refrac’ed using the plug and perf method with 2224 lb/ft of proppant and 53 bbl/ft of fluid. This resulted in an incremental recovery of 367,291 barrels of oil (BO) from this completion, for a total recovery estimate of 438,867 BO, which resulted in a combined recovery factor of 13.5%. If the liner refrac production decline is applied to an AFE of $4 million, the IRR is 102% and NPV is $8.283 million. A new well in the same area yielding similar results on the initial completion has an NPV of $8.518 million, assuming a $6 million AFE. The economics of a refrac’ed well can be competitive to new well offsets based solely on the production following the refrac. The total oil recovery following the refrac was 4.5 times the initial EUR in this case vs the predicted 3.9 multiple predicted by the simulation work done by Xiong discussed above.

While the economics of the liner refrac are encouraging, the analysis of the production decline alone is not the whole picture when the refrac’ed well is a primary or parent well. It Is well documented that infill child wells with offset parent depletion will have asymmetric fracs that do not adequately stimulate the infill drainage area. The estimated ultimate recovery (EUR) losses of 40% were reported by Devon (Elliott 2019) when primary wells are not pressurized prior to the infill child well completion. By using the refrac method and capturing that 40% value, it is worth about $3.407 million, which brings the total NPV for the refrac to $11.690 million, or 137% of the new well NPV (Figure 3 below).

There is a common perception that refracs cannot compete with new well economics, but there is mounting evidence that the returns don’t only match but exceed those of new wells. We have highlighted one example, but there are thousands that fit this profile throughout the United States. A key reason refracs have been avoided by the industry is due to unpredictable results prior to the use of mechanical isolation. As we highlight in this article, refracs with mechanical isolation deserve a seat at the capital budgeting table. Refracs have the benefit of utilizing installed equipment, face less supply chain constraints, get production to market faster, and lower the total carbon footprint. The reduced emissions is attractive to operators in the region that are managing ESG scores, and can balance it between refrac opportunities and new well completions. For operators that don’t have active drilling programs, refracs are even more important because they expand the value of their asset base while hydrocarbon prices are favorable.

The U.S energy industry is currently in a position to capitalize on superior economics while delivering more production quickly, and with a reduced GHG footprint—added bonus! Our ingenuity is being called upon again, and we are in a prime position to save the day once more, if we “follow the science”!

Primary Vision Network and Integrated Energy Services are extremely excited to announce a collaboration aimed to align with operators, and other participants, who want to leverage our analysis for further discovery in and around the refrac market. We believe the opportunity exists for refracs to be an integral part of an operator’s completion program now and for years to come.

We’re offering a battery of services analyzing refrac tracking, downhole consumables, refrac selection, data procurement and validation, completion execution, competitive and market intelligence and so much more.

Our first detailed report on the Eagle Ford is available now at primaryvision.co/product/eagle-ford-summer-of-2022/ or you can schedule time with our Director of Communications Aurora Cowen ( aurora@pvmic.com ) to learn more about our services.

References

Barba, Robert : “Liquids Rich Organic Shale Recovery Factor Applications,” SPE paper 174994 presented at the 2015 SPE Annual Technical Conference and Exhibition, Houston Sept 28-30.

Barba, Robert, and Villarreal, Mark: “Evaluating Refrac Economic Potential and Primary-Infill Relative Well Performance in Permian Organic Shales,” URTEC paper 2662 presented at the 2020 Unconventional Resources Technology Conference, Austin, Tx 20-22 July.

Barba, Robert, Allison, Justin, and Villarreal, Mark: “A Comparison of Latest Generation Frac New Well and Refrac Results with Evidence of Refrac Reorientation,” URTEC paper 3724057 presented at the 2022 Unconventional Resources Technology Conference, Houston, Tx 20-22 June.

Elliott, Brendan: “Fracture Driven Communication: Measurement, Modeling, Mitigation,” SPE 2019 Workshop Well Completions for Unconventional Resource Development Optimization and Parent-Child Interaction, April 9-11 Huntington Beach, Calif

Gabin, Oliver Floyd et al: “Practical Quantification of Sand Distribution from Perforation Erosion Measurements, An Example from Marcellus Shale,” SPE paper SPE 201793 presented at the SPE Eastern Regional Meeting, November 2–3, 2021

Paul Weddle, Larry Griffin, and Mark Pearson: “Mining the Bakken II: Pushing the Envelope with Extreme Limited Entry Perforating,” SPE paper 189880 presented at the 2018 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, 23-25 January

White, Matt presentation at the 2018 SPE/Icota Workshop: Refracturing Through Optimized Interventions, San Antonio, Texas 9-10 October (not published)

Xiong, Hongjie et al: “The Effective Cluster Spacing Plays the Vital Role in Unconventional Reservoir Development – Permian Basin Case Studies,” SPE-199721 presented at the SPE Hydraulic Fracturing Technology Conference and Exhibition held in The Woodlands, Texas, USA, 4-6 February 2020