Interesting papers from the 2023 SPE Hydraulic Fracturing Technology Conference

The 2023 SPE Hydraulic Fracturing Technology Conference was last week, and as usual, it had an outstanding lineup of papers and speakers.

This blog post has a brief lineup of some of the papers that I found most interesting. As in past years, this rundown focuses on papers that I found interesting, based on my own personal interests. Usually, I am most interested in papers that improve our understanding ‘what’s going on’ in the subsurface. Also, I coauthored a paper at the conference, so naturally, I can’t help but include it on this list!

There’s a really interesting paper on the FORGE project by McLennan et al. (2023), but I am saving that for a future blog post that will discuss this week’s Stanford Geothermal Workshop.


Hydraulic Fracturing Test Site #1 Phase 3

Brinkley et al. (2023)

Brinkley et al. (2023) summarize results from the HFTS1 Phase 3 project. This is a follow-up to the original HFTS1 project. Phase 3 included refracturing, additional core, infill wells, and a suite of detailed diagnostics.

The core-through was performed before the refracs, so they sampled the parent-vintage fractures. Across 420 ft of horizontal core, they observed 44 natural fractures and 136 hydraulic fractures, of which 13 contained proppant. The plot of ‘fracture count versus distance’ shows a series of peaks, surrounded by troughs, indicating that the fractures were clustered into swarms. To my eye, it looks like there are about 19 peaks across the interval, working out to about one per 22 ft on average. The natural fractures appear to be playing a relatively minor role; they report that most of the natural fractures were very thin and calcite-cemented. Some of the natural fractures appear to be reactivated, but it is ambiguous to what extent this happened due to core handling.

An image log was run across the same interval, and interestingly, most of the fractures from the core were not visible. Their interpretation was that only the fractures that were sufficiently open to accept drilling mud were observed by the image log. This would be consistent with findings from other core-through studies, which show a large number of hydraulic fractures clustering into swarms, but only a minority of them retaining conductivity and contributing to far-field drainage.

DAS fiber was placed in observation wells offset the refracs. It is sometimes hypothesized that depletion could cause stress rotation during refracs, rotating the fracture orientations. However, the DAS observations from Brinkley et al. (2023) suggest that the fractures remained consistently oriented in the direction of SHmax during the refracs.

Overall, the core and refrac fiber observations appear to be consistent with the conceptual model that we use in most ResFrac simulations. Stimulation is dominated by propagation of hydraulic fractures. Evidently, they cluster into swarms and have small-scale complexity, but overall, they are propagating largely in the direction of SHmax, even in the presence of depletion.

Other tidbits: (a) when a preload was pumped, it mainly flowed into the heel of the well; (b) the repressurization caused by the preload dissipated within 12 hours; (c) in the refracs, they had good perf efficiency at 7 or 12 clusters per stage, but not at 22 clusters per stage; stronger limited-entry improved perforation efficiency; (d) the high cluster count stages appeared to have a strong heel dominance, with much less propagation in the toe section of the stages; (e) surprisingly, they did not see indication that the parent fracs were being reopened during the refrac.


A catalogue of fiber optics strain-rate fracture driven interactions

Ugueto et al. (2023)

As the title suggests, this paper catalogs the strain-rate response caused by various phenomena – frac hits, interception at an angle, reopening of a preexisting fracture, fractures propagating above/below or near the observation well, fluctuations in rate, communication with the previous stage, etc. For each, the paper provides an example from actual field data, as well as a modeling result that matches the observation. This paper can serve as a reference manual for anyone interested in interpreting offset fiber. The examples from field data have remarkable concordance with the model predictions.


Strain-based pressure estimates

Haustveit and Haffener (2023)

This paper is an interesting outgrowth of the HFTS1 Phase 3 work described by Brinkely et al. (2023). The project involved pressure gauges placed along an offset monitoring well during long-term production. The monitoring well was also instrumented with fiber. The authors cross-plot pressure depletion versus DAS strain at the locations of the gauges and observe a linear relationship. The implication is that we can use fiber in offset wells to measure where depletion is happening. This could be very useful because fiber is much cheaper to place in an offset well than pressure gauges, can cover the full lateral, and has better spatial resolution.

The uniformity of far-field drainage is a key uncertainty. With our improving diagnostics, we are able to measure where and how many fractures propagate in the far field. But since proppant trails the fracture tip, we don’t have easy ways to assess the draining length or the spacing/uniformity of the depletion. Diagnostics such a described by Haustveit and Haffener (2023) offer us a path to resolve this uncertainty.


Evaluating Draining Height in the Meramac/Woodford with Microseismic and Geochem

Maxwell et al. (2023)

The STACK play in Oklahoma goes from the Upper Meramac, Lower Meramac, Osage, and Woodford, with a combined thickness of roughly 300 ft. Maxwell et al. (2023) ask the question – do Upper Meramac wells drain from the Woodford and vice-versa?

The microseismic suggests that fractures from the Woodford only grow up into the Lower Meramac and do not reach the Upper Meramac. But interestingly, the fractures from the Upper Meramac grow all the way down into the Woodford. They observe a slowing of propagation as the fractures propagate into the Osage (directly above the Woodford, below the Lower Meramac), which they hypothesize is caused by greater leakoff in that formation because of permeability from natural fractures.

The geochem suggests that all wells – regardless of landing depth from Upper Meramac to Woodford – drain primarily from the Osage and Lower Meramac intervals. However, consistent with the microseismic, the Upper Meramac wells do not produce from the Woodford. The Woodford wells do have some production from the Upper Meramac. However, interestingly, even the Upper Meramac wells shows relative limited production from the Upper Meramac, and mainly produce from Lower Meramac and Osage.

They found that the flow allocation from the geochem did not change over time. However, this is not always the case – they note that, in other datasets, significant changes have been apparent over time.

These measurements will be useful for landing depth optimization, well spacing, and job design.


Sealed Wellbore Pressure Monitoring and Fracture Model Calibration

Olson et al. (2023)

This is a paper that Well Data Labs wrote along with collaborators from Devon and ResFrac. It’s a case study on using SWPM to calibrate a fracturing model. They review a case study using the data from the HFTS1 Phase 3 dataset, using the SWPM to estimate volume to first response for different designs – 7, 12, and 22 clusters per stage. For the model calibration, they used ResFrac’s automated history matching capability, which allows for matching directly to ‘volume to first response.’ The data showed differences in perforation efficiency between the designs, and also gave information on the relative rate of horizontal and vertical fracture growth. The model calibration varied some basic parameters (toughness and toughness anisotropy) to achieve a match to the VFR observations and predicted the variations in perf efficiency. They went a step further and performed a history match to the available production data. It’s a neat demonstration of how VFR observations can be practically and efficiently integrated into the modeling process, which then tees up an economic optimization of frac design for NPV, IRR, etc.


Results from a Parent/Child Industry Study

McClure et al. (2023)

This paper reviews results from the Parent/Child Industry Study that ResFrac organized in 2021 and 2022. The study involved ten high-quality pad-scale datasets, spanning the Bakken, Montney, Midland, and Delaware Basins, contributed by seven companies. For each dataset, the group built models calibrated to the array of field diagnostics, and then ran sensitivity analysis simulations and economic optimizations.

This was a big project with many takeaways, and only a fraction of the total material was included in the paper. A few tidbits: (a) in all cases, diagnostics suggest fractures propagating as largely planar features oriented towards SHmax; fracture length was substantial, 1000s of ft; (b) formations are differentiated by height growth; Montney fractures tended to be confined within layers and long, Bakken fractures tend to propagate 100-200 ft into the Lodgepole and down through the first Three Forks bench, and Midland/Delaware Basin wells tend to have the most height growth and vertical drainage (although, these plays are geographically variable and involve many different landing zones, so it is difficult to generalize); (c) the Midland Basin plays are notable because of the thickness of the pay and the relative lack of height barriers (in most cases); as a result, vertical fracture growth and proppant placement may be relatively beneficial, relative to configurations where ‘non-pay’ is located in the overlying layers (such as the Bakken); this impacts decisions about fluid type and fracture ordering; (d) there is modest economic benefit from running smaller jobs in the child well adjacent to the parent, and larger jobs in ‘outer’ wells that are unbounded on one side; (e) there is modest economic benefit from fracturing the child wells closest to the parent wells first, and then moving away; fracturing towards an unbounded child well can be beneficial, but only if zippering ‘in-line’ so that fracturing is happening in the same corridor as the prior well’s stage, without major time-lag.

In the Montney, as with the SCOOP/STACK, it appears that chemical damage mechanisms can be responsible for additional production loss, especially at parent wells. This makes it relatively more beneficial to pump smaller jobs in the nearest child well and to consider chemical remediation treatments, or changes to the frac fluid.

Vertical frac hits tend to cause more significant production loss than horizontal frac hits (as long as there are not strong stress barriers between zones). This favors ‘full-stack’ developments that hit all landing depths simultaneously and then move laterally.

The modeling results and operator experience were lukewarm on preloads. There is likely benefit from small-volume preloads to prevent proppant influx and protect the mechanical integrity of the well. But otherwise, production uplift (at either parent or child) is expected to be modest. An exception – some preloads are pumped with chemicals such as surfactants. Chemical treatments can be quite beneficial, and so an observed uplift might come from the chemical treatment rather than the repressurization effect.

There are many case-specific nuances and strategies that can mitigate negative impacts. But ultimately, there is no silver bullet. The best solution is to optimize design to maximize economic performance in the presence of parent/child interactions. In the paper, we show examples how this can be done with ResFrac’s automated optimization tool.

When I presented the paper, in the Q&A, someone asked about refracturing the parent. We did not specifically address that topic in the paper. But in general, I think it’s often a good idea. In parent wells that were fractured with relatively wide cluster spacing and small job size, there is usually a good opportunity to improve recovery with a higher density refrac design with a new liner (for example, see Barba and Villarreal, 2023), and there may be a knock-on benefit to neighboring child wells. However, if the parent well is relatively more recent and completed with a higher density design, refracs are likely to be less successful.



Barba, Robert, and Mark Villarreal. 2023. The economics of refracturing in the Haynesville. Paper SPE 212371 presented at the Hydraulic Fracturing Technology Conference, The Woodlands, TX.

Brinkley, Kourtney, Cameron Thompson, Jackson Haffener, Sarah White, Chris Ketter, Jerret Borell, Joe Cominsky, Eric Hart, Kyle Haustveit, Matthew Herrin, Peter Jones, Kevin Pelton, Kevn Pfau, Buddy Price, Jon Roberts, and Molly Turko. 2023. Redefining recoverable reserves in the Eagle Ford: Refracs and infill development lessons learned from the Hydraulic Fracturing Test Site 1 (HFTS) Phase 3. Paper SPE-212340-MS presented at the Hydraulic Fracturing Technology Conference, The Woodlands, TX.

Haustveit, Kyle, and Jackson Haffener. 2023. Can you feel the pressure? Strain-based pressure estimates. Paper SPE-212364 presented at the Hydraulic Fracturing Technology Conference, The Woodlands, TX.

Maxwell, Shawn, Richard Britto, Geoff Ritter, John Sinclair, Aaron Leavitt, Faye Liu, and Jana Bachieda. 2023. Evaluation of effective drainage height through integration of microseismic and geochemical depth profiling of produced hydrocarbons. Paper SPE 212314 presented at the Hydraulic Fracturing Technology Conference, The Woodlands, TX.

McClure, Mark, Magdalene Albrecht, Carl Bernet, Craig Cipolla, Kenneth Etcheverry, Garrett Fowler, Aaron Fuhr, Amin Gherabati, Michelle Johnston, Peter Kaufman, Mason MacKay, Michael McKimmy, Carlos Miranda, Claudia Molina, Christopher Ponners, Dave Ratcliff, Janz Rondon, Ankush Singh, Rohit Sinha, Anthony Sung, Jian Xu, John Yeo, and Rob Zinselmeyer. 2023. Results from a collaborative industry study on parent/child interactions: Bakken, Permian Basin, and Montney. Paper SPE-212321 presented at the Hydraulic Fracturing Technology Conference, The Woodlands, TX.

McLennan, J., England, K., Rose, P., Moore, J., and Barker, B. 2023. Stimulation of a High-Temperature Granitic Reservoir at the Utah FORGE Site. Presented at the SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, TX.

Olson, Karen, Joshua Merritt, Rair Barraez, Garrett Fowler, Jackson Haffener, and Kyle Haustveit. 2023. Sealed wellbore pressure monitoring (SWPM) and calibrated fracture modeling: The next step in unconventional completions optimization. Paper SPE-212367 presented at the Hydraulic Fracturing Technology Conference, The Woodlands, TX.

Ugueto, Gustavo, Kan Wu, Ge Jin, Zhishuai Zhang, Jackson Haffener, Mojtaba Shahri, David Ratcliff, Rob Bohn, Andres Chavarria, Yinghui Wu, Arter Guzik, Aishwarya Srinivasan, Richard Gibson, Alexei Savitski. 2023. A catalog of fiber optics strain-rate fracture driven interactions. Paper SPE-212370 presented at the Hydraulic Fracturing Technology Conference, The Woodland, TX.

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