A Process for Evaluating and Optimizing Frac Plug Performance Free

This study outlines a method for identifying, prioritizing, and evaluating the performance of key frac plug design elements and operational practices. Currently, there are no industry standards for qualifying frac plugs and therefore no baseline to compare performance among various products. This creates an environment where the qualification is left up to the manufacturers who rely heavily on input from individual operators. The design of frac plugs is being influenced by numerous conflicting performance drivers for run-in, frac, and drill-out requirements. Additionally, certain operational practices have led to setting frac plugs off target depth, which can cause isolation issues. Given the various design and environmental factors affecting frac plug performance, stage isolation quality is often overlooked and rarely quantified. In the absence of advanced diagnostics like fiber optic measurements, assessing frac plug isolation performance can be challenging. This added complexity often shifts the focus to more easily measurable metrics, such as running performance and drill-out performance.

In this study, specific testing protocols were selected and combined with multiple data sources to create an integrated data set. This approach aims to capture quantifiable metrics that allow engineers to analyze detailed failure mechanisms and identify major factors affecting the overall performance of frac plug products, with a strong emphasis on the quality of isolation. Previous studies often relied on a single data source to draw conclusions, which does not adequately capture discrete failure mechanisms, or the impacts associated with loss of confinement. This study focuses on evaluating frac stage confinement through integrating multiple data sets including treatment pressure analysis, radioactive tracers, drill out performance, high-resolution ultrasonic imaging of frac plug set depths and perforation erosion measurements. This study details the methodology and process for integrating these datasets, using a case study to uncover meaningful outcomes. These findings can guide future design improvements and necessary adjustments to operational practices, enhancing overall performance.

This case study builds on the content shared in Watson et al 2022 where key design elements of frac plugs were identified to minimize the bypass of stimulation fluids around the exterior of a frac plug. The previously identified key design elements were used to identify and rank multiple frac plug design offerings. Once the design ranking was completed, the top six ranked designs were incorporated in an in-well trial. The test had eight stages per frac plug, including radioactive tracer use, treatment pressure analysis, frac plug set depth evaluation, and perforation erosion measurement.

This study's main objective was to develop a technical-based frac plug selection criteria that demonstrates high isolation performance verified through integrating multiple datasets.

First, the team identified the priorities of the study and associated business impact. The priorities established were ranked in importance as follows:

• Frac stage isolation – the ability to place the designed treatment volume and proppant in the desired interval.

• Operational efficiency- Successfully deploying, setting, and drilling out the plug.

• The unit cost of the frac plug and setting tool.

• Assess current operational practices to identify necessary improvements.

Frac stage isolation is prioritized over all other metrics as it is deemed to have the largest impact on the well economics and improving the development of the acreage. Operational efficiency was also prioritized and focused on minimizing the non-productive time associated with deploying frac plugs and improving drill out times. The cost of the tool is deemed inconsequential as the financial impact of the first two priorities far outweighed the unit cost of a frac plug.

The following section will outline the logic behind the design criteria identified to establish candidates for the trial.

The main objective of a frac plug is to provide complete zonal isolation during the hydraulic fracture treatment. Many different frac plug designs exist in the industry today. Frac plugs are constructed with a composite or a dissolvable material. Dissolvable frac plugs are mainly used if the drill-out BHA cannot reach a final depth in horizontal well applications. Composite frac plugs are predominantly used for zonal isolation in horizontal well applications. Some composite designs are short and compact to drive higher drill out and pump down efficiencies. In recent years, the effectiveness of dissolvable frac plugs to isolate stages has come into question. The effectiveness of single slip composite frac plugs to provide zonal isolation has also come into question due to the short and compact nature of their design. This section outlines critical design features that improve the chances of zonal isolation in horizontal-well hydraulic fracturing applications.

Watson et al 2022 highlighted a case study in the Montney formation that examined frac plug performance and failure mechanisms. The study demonstrated the improvement in frac plug isolation performance through maximizing the anchoring reliability and minimizing the bypass of fluid around the exterior of the frac plug through robust sealing element design considerations. These design features were incorporated into the design priorities for frac plug selection in this case study.

In this case study, composite frac plugs were chosen, except for the button slips, which were made from non-composite materials. The supplier or manufacturer was requested to specify the material characteristics of all frac plug components —both metallic and non-metallic—and ensure their suitability for the specified environmental conditions outlined in the functional specification. Additionally, each supplier or manufacturer provided documented specifications for all materials. A thorough design review was conducted with each supplier to verify physical properties, including dimensional data, pressure ratings, temperature limits, and load capacities.

Among composite materials, there exist several types that can impact the performance of frac plug products. Typically, a frac plug consists of three primary components: the body, outer components, and the slips. Each of these components may utilize different types of composite materials. Understanding the design specifications, as well as conducting thorough design verification and design validation, is essential for identifying whether a failure observed in the field is related to well parameters or operational conditions based on diagnostic data collected during the test campaign.

Interlocking design considerations focuses on how the frac plug is constructed to maximize and maintain the setting force in the tool. Typically, the presence of top and bottom slips allows for greater retention of the setting force to be maintained in the frac plug, minimizing frac plug movement through normal operating practices and pressure cycles, and maximizing the radial force being applied from the sealing element to the casing wall. Fig. 1 features ultrasonically derived images showing evidence of button movement and erosion around the sealing element of a frac plug with a single set of buttons (Watson et al 2022).

Slip design plays a pivotal role in the overall functionality and reliability of frac plugs. Here is why it is critical:

1. Retention and Sealing: Frac plugs are used to isolate specific sections of a well during hydraulic fracturing operations. The slips are responsible for anchoring the frac plug within the casing. Proper slip design ensures that the frac plug remains securely positioned, preventing unintended movement or premature release.

2. Initial setting: Slips are designed with hardened components to penetrate the inner diameter (ID) of the casing and secure the slip in place. These slip segments must have enough hardness to penetrate the casing effectively, while also possessing sufficient toughness to withstand the impact loads from the setting forces. If the casing is too hard or if there is a manufacturing defect causing the slip material to yield, the anchoring system can be compromised. Additionally, if the slip material lacks adequate toughness, the sharp edges of the slips could chip or break.

3. Load Transfer: During fracturing, substantial forces act on the frac plug. These forces include axial loads (due to fluid pressure) and radial loads (from the surrounding casing). A well-designed slip assembly efficiently transfers these loads to the casing, maintaining well integrity. If the load is not evenly distributed, it can increase localized stresses on the slip or cones, potentially compromising performance. Another reason for uneven force distribution through the slips is setting the frac plug in oval casing. Even a slight deviation can cause a non-uniform bite pattern which can compromise performance.

4. Functional Requirements: Slip design directly impacts the ability of the frac plug to withstand downhole conditions. Suppliers must validate that the slips meet functional requirements, such as load-bearing capacity, slip coefficient, and gripping efficiency.

5. Validation Process: Suppliers undergo a thorough validation process to ensure slip designs meet functional requirements. This involves physical testing, simulations, and analysis. The goal is to verify slip performance under realistic downhole scenarios. Any deviations from expected behavior prompt adjustments to the design.

In summary, slip design directly influences frac plug functionality, well integrity, and successful fracturing operations. Suppliers’ diligence in verifying and validating slip designs ensures reliable zonal isolation and contributes to overall well productivity.

Most slips are designed to break apart when the tapered edge of the cone is forced into the corresponding tapered edge under the slip housing. One common slip design features a continuous ring of material with machined or molded webbing between each segment, intended to break apart at a predetermined force. Another design involves individual slip segments held together by a frangible band. If the slip encounters force greater than the designed break-up force, either from an obstruction or the cone, the slip segments will become free to ride up the cone and contact the casing. Various design features can mitigate movement if the cone encounters an obstruction in the wellbore.

Bypass fluid velocity is another key factor in preventing conditions that can lead to a preset frac plug during frac plug pumpdown operations. Various methods are available for determining bypass velocity limits through surface flow loop testing. Testing the range of bypass velocity that causes the frac plug to set or swab off the element is essential for defining the operating limits for the required functional requirements.

One approach to mitigating preset risk is to incorporate design features that allow the lower cone to transfer external loads into the mandrel when encountering obstructions during run-in. There are several other methods to divert forces away from the slips during run in, and each design feature should be validated against the expected loads to ensure it performs as intended.

In summary, understanding each supplier’s approach to validating resistance to presetting and operating limits can help mitigate costly downtime associated with preset frac plug events.

The sealing element and anti-extrusion mechanism mitigate fluid bypass on the exterior of the frac plug, a crucial component to successful stage confinement. This is done by optimizing the contact area of the sealing element when the frac plug is in the set position. The anti-extrusion design is focused on how the bottom side of the sealing element is supported while in the set position to prevent the elastomer from flowing or extruding through the void space between slips as high differential pressure is applied to the frac plug.

Explosive wireline pressure setting assemblies (WLPSA), more commonly referred to as setting tools, rely on igniting energetics to expand gases, generating the mechanical force needed to set composite frac plugs. Often overlooked, the setting tool is a crucial component in the bottomhole assembly (BHA), playing a significant role in the performance of a plug-and-perf operation. Setting tools come in several types, each with distinctive characteristics. While it is not common for manufacturers to consider setting tools when qualifying and validating product performance, it is still important to understand the relationships between stroke length, force output, and the rate of applied force among different setting tools and their impacts on the performance of frac plug products. Replicating the characteristics of explosive setting tools during product qualification can provide additional insights and confidence in the performance. It is important to understand which setting tools have been qualified for the frac plug and if there are any gaps in qualification.

This frac plug trial took a unique approach when seeking to assess frac plug isolation. If one were to look at only one diagnostic approach, the results may have been inconclusive or provide insight on only a portion of the actual events taking place during the hydraulic fracturing treatment. This study integrated four different diagnostics (perforation entry-hole erosion, radioactive tracers for tagging proppant, treatment rate/pressure plots, and casing wear patterns at frac plug setting depths) to validate isolation. In many cases, the independent evaluation techniques provided the same determination on frac stage isolation, providing high confidence in isolation assessment. In addition, the integrated diagnostics provided insight into what potential failure mechanism occurred when stage isolation was not achieved. The next sections will cover how the test was set up and how the diagnostics were used to determine frac plug performance.

Based on the frac plug selection criteria, six frac plug vendors were selected that met all the requirements mentioned in the above section. To simplify the test and optimize cost for the integrated diagnostics, six different frac plugs were used tested in one wellbore. The one-wellbore approach ensured all six frac plugs were exposed to similar differential pressures, proppant volumes, and treatment conditions. Each frac plug type was run on eight consecutive frac stages as outlined in Fig 2. This process was repeated sequentially for all frac plugs with the testing process spanning over 48 consecutive frac stages. Within the eight stages of each frac plug trial, three were traced with radioactive tracer, two stages contained a planned shutdown, and the rest were pumped as normal. After the hydraulic fracturing job, each of the frac plugs were drilled out and the mill times, returned frac plug material weights, and the returned cuttings shape were documented. After the drill out was complete, the test intervals were logged with a radioactive tracer investigation sonde for determining proppant distribution along the lateral and an ultrasonic imaging tool for evaluating erosion and wear at the perforation entry holes and the frac plug setting depths, respectively.

Radioactive tracing can be a highly effective method for analyzing zonal isolation. It involves pumping one or more radioactive isotopes with proppant during the hydraulic fracturing treatment. After the well is drilled out, a wireline conveyed spectral logging tool is pumped down for measuring the gamma ray energy distributions to determine the type and concentration of radioactive isotope along the lateral. Fig. 3 illustrates what an isolated stage looks like. The radioactive tracer is contained within the top and bottom of stage 26 with little indication of tracer in the downstream stage 25 location. On the contrary, Fig. 4 represents an isolation failure. The radioactive tracer pumped in stage 50 was also observed throughout the stage 49 interval, indicating a frac plug leak or failure.

Another potential failure point can occur at the interface between the frac ball and the frac plug ball seat. This type of failure is often observed during intermittent shutdowns due to either pre-frac step-down testing or surface equipment related issues. In Fig. 5–7, three different outcomes are shown in planned-shutdown tests. Tracer A was pumped during the first half of the treatment, followed by an intentional shutdown and then tracer B was pumped during the second half of the treatment. The primary objective was to determine whether tracers A and B remained confined to the target stage. This test methodology is designed to simulate worst-case pressure-cycling scenarios for validating the performance of various frac plug products. Fig.5 showed no isolation of any tracer, indicating a failure prior to the intentional shutdown. A combination of outcomes can be seen in Fig.6. In this shut down stage, Tracer A was isolated, and tracer B traveled into the previous stage; which was a strong indication that the frac plug was not effectively isolating the zone after the shutdown event. Fig. 7 showed isolation before and after the planned shutdown. Overall, the shutdown tests with the dual radioactive tracers showed a 50% failure rate for zonal isolation.

Fig. 6 indicates that after the shutdown test, that stage 45 was not isolated since tracer B was found in the previous stage 44. The integrated diagnostic approach revealed insights regarding the location of the leak path that developed after the shutdown. In Fig. 8 below, the mill wear and lower button impressions in the casing indicate the frac plug remained intact after the hydraulic fracturing treatment. The mill wear length is within normal range for this frac plug design. Also, there is no indication of flow between the outside diameter of the frac plug and inside diameter of the casing. This can be concluded because no casing wall loss was observed in the ultrasonic imaging that would represent frac plug element bypass. Based on this assessment, the leak path must have occurred at the interior of the frac plug, probably at the interface of the frac ball and frac plug ball seat.

During post frac plug drill-out operations inside 5.5 in. casing, a roller cone bit is typically used for removal of the frac plugs. Roller cones with tungsten carbide insert (TCI) cutters are prone to creating a distinct wear pattern on the casing wall when weight is applied on the bit during drill out. Observing mill wear on the internal diameter of the casing indicates that the frac plug is stationery, and material has been removed during the drill-out process. The extent of milling damage can vary based on several factors, with one key factor being the volume and type of material and/or stacking of components from previous frac plugs being milled at a specific location. Identifying and isolating milling-related damage can help distinguish important variations when assessing overall frac plug performance. Analyzing extended milling damage using imaging and drill-out data can offer deeper insights into the factors affecting drill-out behavior. In this scenario, there is a strong correlation between frac plugs that provided good isolation during the frac treatment, efficient drill and wash times between frac plugs, and a reduced incidence of extended milling damage. These results when combined with other KPI metrics can be used to aid in selecting products for a specific environment and optimize operational parameters to maximize performance.

The exhibits below show three specific measurements gathered for each frac plug type. The extracted measurements taken from each sample for comparison are the maximum measured wall loss, a circumferential measurement between frac plug button groups, and an axial measurement between the upper and lower rows of slip buttons. The third and final measurement identified as extended milling damage represents the length of casing wear associated with the shortest and longest milling times for frac plug vendor 1, 4, and 5. This is intended to show the relationship between extended milling times and the amount of milling damage observed for each frac plug vendor.

The bar chart in Fig. 9 below illustrates the number of frac plugs that successfully isolated the frac treatment versus those that failed, in relation to drill-out performance. A strong correlation was observed between frac plugs that provided good isolation, efficient drill and wash times between frac plugs, and a reduced incidence of extended milling damage. These results when combined with other KPI metrics can be used to aid in selecting products for a specific environment and optimizing operational parameters to maximize performance.

Fig. 10–12 show three specific measurements gathered for each frac plug type. The extracted measurements taken from each sample for comparison are the maximum measured wall loss, a circumferential measurement between frac plug button groups, and an axial measurement between the upper and lower rows of slip buttons. The third and final measurement identified as extended milling damage represents the length of casing wear associated with the shortest and longest milling times for frac plug vendor 1, 4, and 5. This is intended to show the relationship between extended milling times and the amount of milling damage observed for each frac plug vendor. Fig. 10 shows a rendering that depicts the button pattern for the upper and lower rows of slips for frac plug vendor #1. This frac plug demonstrated the best performance during both the frac treatment and drill-out, exhibiting the lowest incidence of extended milling damage among all tested frac plugs.

Fig. 11 shows a rendering of Vendor #4 slip button pattern for the upper and lower rows of slips for frac plug #53 and #50. Frac plug vendor #4 ranked 4th best, with 2 failures during frac and 3 instances of extended milling damage and had the third longest average drill-out time. Frac plug #50 failed during the frac treatment and shows evidence of extended milling damage with a mill time of 10 minutes. Frac plug #53 held and isolated during frac and shows no evidence of extended milling damage with a mill time of only 2 minutes.

Button slip pattern for the upper and lower rows of slips from Vendor #5 is shown below in Fig. 12. This frac plug ranked 5th best, with 4 failures during frac treatments and 5 instances of extended milling damage and had the longest average drill-out time out of all vendors. Frac plugs #35 and #41 both held and isolated during the frac treatment.

Lab and field studies have shown that proppant-induced perforation entry hole erosion occurs during limited entry treatments (Cramer et al 2020). Entry hole is the term for the part of the perforation that penetrates the casing or pipe. Entry hole erosion is a two-step process. As shown in Fig. 13, proppant interactions initially smooth and bevel the entry-hole inlet or entrance, with minimal enlargement of the outlet or exit part of the entry hole (Wu et al. 2022). The entry hole outlet is usually the primary determinant of perforation friction pressure since it is usually the location of smallest cross-sectional flow area after the erosion process starts. Eventually, erosion progresses to the exit side of the casing, starting a second entry-hole growth period characterized by a progressive, steady-state increase in the entry-hole-outlet diameter.

Fig. 14 was derived from a pressure-analysis-based study of limited entry treatments (Cramer 1987a, Cramer 1987b). It supports the concept of the two-step erosional process and introduces two empirically derived erosional components – critical proppant mass, the quantity of proppant necessary for erosion to progress to the perforation entry hole outlet/exit and stable-growth erosion rate, the growth of the entry hole outlet/exit as a function of proppant volume once erosion progresses to the entry hole exit.

Perforation entry-hole erosion is a quasi-linear function of the amount of proppant moved through it. Although the exact physical processes controlling entry-hole erosion are only partially understood, it is influenced by factors such as initial entry hole size; proppant particle size, angularity, and hardness; pipe thickness and hardness; work hardening near the surface of the entry holes due to metal compression by the perforating jet; and perforating gun orientation.

Ultrasonic-based systems can measure perforation entry holes at multiple cross-sections. The standard ultrasonic measurement is taken at the minimum equivalent perforation diameter (D_EQ), which is typically at the outlet or exit part of the entry hole.

where A = cross-sectional flow area of the post-treatment perforation outlet or exit part of the entry hole, in².

The hole outlet D_EQ is the relevant dimension for determining perforation friction pressure and when using the standard erosion-rate model for computing proppant distribution among clusters. In the subject well, measurements were computed at both the inlet/entrance of the hole and the outlet/exit of the hole. Prior to proppant-induced entry hole erosion, the inlet and outlet dimensions are similar. As proppant starts to flow through the perforation entry holes, the inlet or entrance of the hole erodes preferentially, with the erosion front reaching the exit part of the hole after a critical mass of proppant has been pumped, as indicted in Figs. 13 and 14. Considering this, the ratio of inlet hole size (entrance hole) to outlet hole size (exit hole) is initially close to unity (1.0), increases to a relatively high ratio while erosion is limited to the upstream side of the hole, then stabilizes or sometimes decreases as the erosion front breaks through to the entry hole outlet, which then erodes/grows at a steady rate along with additional growth at the inlet part of the entry hole. The ratio of inlet D_EQ to outlet D_EQ versus outlet D_EQ for all perforations imaged during the post-frac ultrasonic survey and for untreated calibration perforations imaged prior to the treatment of one of the frac stages are shown in Fig. 15. Although the data points are significantly scattered, there are two distinct groups. The upper group of blue points represents the perforations measured after the frac treatments. The lower group of orange points represents the untreated calibration perforations measured prior to the treatment in a single frac stage. There is no intermingling of the two groups and in all cases, the D_EQ ratios for calibration perforations are less than the post-treatment D_EQ ratios. This plot provides evidence that fluid and proppant passed through all perforations in this multistage fracturing application (Cramer and Friehauf 2024).

In this study, three perforation-erosion-based methods were used to allocate proppant among perforation clusters for assessing treatment uniformity along the lateral. In all cases, an underlying assumption is that growth of perforation entry-hole diameter (D_EQ), area or volume is proportional to the amount of proppant passing the entry hole.

The first allocation method is based on fractional erosion. In this method, the eroded perforation entry-hole outlet (exit hole) area is computed for each perforation, then proppant is allocated to it and the associated perforation cluster by dividing its eroded area by the total eroded hole-outlet area for all perforations in the frac stage. The second allocation method is based on the two-component erosion model shown in Fig. 14 and is an expansion of the fractional erosion method. It is described in detail by Watson et al. (2022). A quantity of proppant necessary for erosion to progress from the perforation hole inlet on the inside of the pipe to its outlet or exit on the backside of the pipe (i.e., critical proppant mass component) is assigned to each perforation. Following breakthrough of the erosion front to the hole outlet, the hole-outlet D_EQ is assumed to expand from its initial pre-treatment condition, with its growth proportional to the proppant volume moved through the perforation (i.e., stable growth component). This method provides a potentially more accurate estimate of proppant allocation among perforation clusters. The calculations for each perforation were performed using Eq.2.

where V_PROP-P = proppant volume flowed through the perforation, lbs.; D_EQ final = equivalent hole outlet diameter as determined from post-frac ultrasonic imaging analysis, in.; D_EQ initial = average equivalent hole outlet diameter for untreated baseline perforations, in.; E = perforation erosion rate during the stable growth period, in./1000 lbs. of proppant; C = critical proppant mass per perforation, lbs.

The third allocation method is based on volumetric erosion. The partial cone equation (Eq.3) is used to compute perforation hole volume at the beginning of the treatment using calibration-perforation measurements and end of the treatment using post-treatment entry hole measurements. The difference in these measurements is used to compute the volumetric perforation entry hole growth due to proppant induced erosion. Proppant is assigned to each perforation on a percentage basis, dividing the volumetric entry hole growth for that perforation divided by the total volumetric entry hole growth for all perforations in the frac stage.

where V_PERF = volume of perforation entry hole, in³, W = pipe thickness, in.

All three methods were used in this study to compute cluster uniformity and heel/toe distribution, both with respect to proppant. Pre-job perforation hole inlet and outlet measurements were performed on a single treatment stage, and these measurements were used as a base for erosion and proppant allocation calculations for all frac stages, using the mean average hole diameter as the base. This was a reasonable approach since zero-phase, high-side perforating was planned for all stages (12 o’clock position, phase angle azimuth = 0°) and as shown in Fig. 16, the orientation outcomes were close to design, providing a consistent perforating environment with respect to gun clearance (Snyder et al. 2021). Basic treatment parameters were the same for all 48 frac stages evaluated in this study. Four hundred thousand (400,000) lbs. of in-basin 40-140 mesh frac sand was pumped with slick water via 8 perforation clusters spaced 25 ft apart, with each cluster containing 3 perforations (24 perforations total). The maximum injection rate was 90 bbl/min.

As shown in Figs. 17 and 18, there was a significant range of variation in the D_EQ of measured inlet and outlet calibration (base) holes. The variability is random in nature and typical for shaped-charge jet perforating. Its impact is reduced as the number of perforations per cluster increases, by the process of statistical averaging. For the calibration perforations, the coefficient of variation (CV, Eq. 4) decreased by 40% and 29% for the hole outlet and inlet, respectively, when basing calculations on the average D_EQ for each cluster. For all frac stages, there were 3 perforations for each of 8 clusters. Reducing the CV of the perforating system enhances the reliability of erosion-based calculations and leads to more uniform distribution of fluid and proppant along the lateral (Cramer et al. 2023).

The post-treatment wellbore cleanout operation is essential for obtaining reliable results from downhole perforation imaging surveys. If sand or other debris is lodged in a perforation hole, it cannot be accurately measured with an ultrasonic device. As a quality control measure for this study, analysis based on perforation erosion was only performed on frac stages that had a high percentage of measured perforations. Frac stages with less than 21 measurable perforations (of the 24 total perforations) or in which all the perforations in one or more clusters were not observed measurable were excluded from comparative analysis. Of the 48 total frac stages, 40 stages were included (83% of total) and 8 were excluded. Of the 8 unanalyzed stages, five were non-isolated stages and 3 were isolated stages.

A quality check for assessing the accuracy of downhole imaging measurements is performing high quality step-down tests at the end of the frac stages to independently derive the average hole-outlet D_EQ (Cramer and Friehauf 2024). This method depends on precise knowledge of pipe friction, which at a minimum requires accurate measurement of fluid density, and the placement of precision gauges at the wellhead and heel of the lateral. Since a downhole gauge was not installed in the study well, this quality check was not implemented.

The results of perforation erosion analysis and its relationship to the isolation characteristics of frac plugs are summarized in Tables 1–3. Frac plug isolation was determined in two ways. One method incorporated multiple diagnostics, specifically post-frac tracer survey of proppant tagged with radioactive (RA) isotopes, investigation of casing-wall erosion and markings from frac plug slips and milling operations during well cleanout, and analysis of treatment job plots. Each frac stage was evaluated in this way and judged as isolated or non-isolated. This is designated in this study as the comprehensive method. The second method was based solely on the results of the post-frac RA isotope survey, the most definitive method for determining isolation, and thus was limited to the 17 frac stages tagged with RA isotopes.

Plots of uniformity index, eroded perforation entry hole volume, and post-treatment perforation entry hole inlet and outlet D_EQ for each frac stage are exhibited in sequential order in Figs. 19–21. Null values are for stages not meeting the quality control criteria. The dashed black lines are the mean averages for the respective parameters. Green dots represent isolated frac stages. Red dots indicate non-isolated frac stages. Black arrows are for eight pairs of frac stages, showing the directional trend of the measured parameter for cases in which an isolated stage is preceded by a non-isolated stage. Frac Stage isolation was determined from comprehensive analysis.

Results for the paired stages are also shown in Tables 1–3. The paired stages are significant in that proppant from other non-isolated stages was prevented from entering and re-eroding perforations of the paired downhole non-isolated stage, due to the effective barrier created by the uphole isolated stage. This provides a best-case contrast for evaluating the benefit of frac plug integrity and frac stage isolation, although sometimes tipping the scales in favor of the isolated stage since in several of these paired well cases, isolation was not achieved in the stage following the isolated stage.

On average, isolated frac stages were associated with a higher uniformity index, greater eroded perforation hole volume and area, and more proppant received than non-isolated stages, indicating that frac plug integrity leads to a more orderly distribution of proppant. But on a stage-by-stage basis, post-treatment perforation entry hole inlet and outlet D_EQ and eroded perforation entry hole area and volume served as the best indicators for showing the advantage of treatment isolation. In all but one paired-stage case (i.e., entry hole outlet D_EQ, stages 33 to 32), the isolated stage had a higher dimensional value than the non-isolated stage. Yet the uniformity index was higher for the non-isolated stage in half of the paired-stage cases. The mixed result with the uniformity index is understandable because proppant can still enter all the unplugged perforations exposed in a frac stage even when losing some proppant to previously treated stages due to isolation failure, and from reentry of proppant due to loss of isolation from subsequent frac stages. As evidenced by the heel/toe distribution shown in Table 3, proppant partitioning along the lateral for a given frac stage was balanced overall, regardless of stage isolation characteristics or the evaluation method.

There were 12 frac stages with planned mid-job shutdowns. As shown in Fig. 22, eight of the 12 frac stages met the QC criteria of 21 or greater measured perforation entry holes per frac stage and are indicated by an open dark blue circle. Four of the 12 frac stages were assigned null values due to an excessive number of plugged perforation entry-holes and are indicated by dark blue circles infilled with green or red depending on whether the stages were isolated or non-isolated, respectively. Only three of the 12 frac stages had values close to the mean average for volumetric erosion and all are isolated stages. Five of the 12 stages showed either excessively high or low entry-hole erosion volume and four of the 12 stages showed significant post-treatment entry-hole plugging (i.e., null value stages). However, frac stage isolation was maintained in six of the nine "non-average-erosion" cases.

Regardless of the effect on frac stage isolation, mid-job shutdowns often impact entry-hole erosion, most likely by restricting flow into previously unrestricted perforation clusters. If this is occurring, one or more perforation clusters could be starved for proppant while the remaining unrestricted clusters receive a disproportionate amount of proppant. This topic requires more investigation but based on the findings of this study, mid-job shutdowns including pad-fluid step-down tests should be avoided when possible.

Methods for calculating the average proppant distribution among perforation clusters for the 17 frac stages in which proppant was tagged with RA isotopes are compared in Fig. 23. Radioactive tracer distribution is based on the counts of gamma ray energy measured during the post-frac spectral gamma ray logging survey. On average, it indicated a strong bias toward the two perforation clusters at the toe end of the frac stages. This result was at odds with distributions determined by the three methods of perforation entry hole erosion analysis, which all showed a more balanced proppant distribution with a slight heel bias. The depth of investigation of the spectral gamma ray logging tools is approximately 2 feet and provides insight only on distribution of proppant in the immediate proximity of the wellbore, after post-treatment wellbore cleanout operations. As shown in Fig. 14, perforation erosion is impacted by the entire volume of proppant pumped during the treatments and is a more reliable indicator of the amount of proppant that flowed through the perforations and clusters. The application of RA proppant tracers is excellent at determining the extent of proppant coverage along the lateral and was essential for this study. But it has limited value in providing quantitative analysis of proppant distribution.

There are aspects of the perforation entry-hole erosional data that are concerning. As shown in Figs. 19-22, the final 13 frac stages (stages 53 to 65) were all judged to be isolated, as determined by the comprehensive method. Yet there is significant variation within that subset of frac stages regarding the calculated eroded entry-hole volume and measured entry-hole inlet dimensions. Variability is not as great for the measured entry-hole outlet dimensions, possibly indicating a difficulty in measuring the entry-hole inlet or an over-emphasis on its importance. But there are other possibilities including changing erosional behavior due to the previously discussed frac job shutdowns, widely variable initial entry-hole dimensions, non-linear relationship with proppant and entry-hole erosion, proppant inertia effects, potentially chaotic nature of entry-hole erosion, overall entry-hole measurement error, and interpretation error regarding frac stage isolation.

Perforation erosion analysis should not be used as the sole diagnostic method for assessing treatment isolation and effectiveness when there are problems with frac plug integrity. Rather, its utility is as a complementary method adding to the overall insight provided by the multiple diagnostics introduced in this paper.

Plots of rate, wellhead pressure and proppant concentration versus job time were evaluated to see if there were characteristic patterns relating to known instances of isolation integrity or failure as indicated by RA tracer analysis. Although patterns were deduced in some cases, there were other cases in which differences in treatment characteristics among isolated and non-isolated treatments were not apparent.

Fig. 24 compares the treatment behaviors of isolated and non-isolated frac stages which were separated by 1436 ft of lateral length. In the non-isolated stage, key events consisted of a sharp pressure break prior to proppant reaching perforations, little pressure change when proppant did hit, a rapid pressure drop of 350 psi seven minutes after proppant hit (indicated by brown arrow) and several stepwise increases in surface treating pressure for the duration of the treatment. In total, the pressure responses suggest premature failure of the frac plug to contain the treatment, lack of a proppant scouring effect due to communication to previously treated clusters, and later bridging of proppant due to the treatment being spread out over 16 clusters instead of only the targeted 8 clusters. These events were in sharp contrast to the isolated stage, which exhibited a sharp pressure break only after proppant reached perforations followed by a gradual decline in treating pressure as perforation erosion progressed.

Another comparison of isolated and non-isolated frac treatments is shown in Fig. 25. These treatment stages were separated by 1437 ft of lateral length. In contrast to the above case, treatment behaviors are similar. The only discernable difference was a 200 psi increase in treating pressure on the non-isolated treatment stage as maximum proppant concentration was approached (marked by brown arrow), possibly indicating restricted flow into a single perforation cluster. But there were no clear signatures indicating isolation failure.

A comparison of frac stages incorporating a planned hard shutdown near the treatment midpoint is shown in Fig. 26. Isolation was maintained in all cases during the first part of the treatment (before the planned job shut down). Treatment stage 45 failed to maintain isolation following the shut down while stages 29, 53 and 61 maintained isolation throughout. In contrast to the isolated stages, stage 45 showed a significantly lower treating pressure on resumption of injection, dropping below its stabilized pressure before flush on the initial treatment. It also exhibited a rapid pressure drop of 300 psi about halfway through the second injection (second blue arrow), a possible indicator of additional loss of frac plug containment.

Most of the differences in treatment behavior between isolated and non-isolated treatment stages were subtle, differing from the clear-cut correlation between treatment behavior and degree of treatment isolation in a Montney case study (White et al. 2020, Cramer and Zhang 2021). In that case, dissolvable frac plugs and frac balls were used and most of the isolation failures were severe and occurred soon after proppant reached downhole, resulting in significant casing erosion, and sometimes casing breeches. Composite frac plugs and non-dissolvable frac balls were used in this case study, and isolation failures were usually less severe in nature. For most of the failed frac plug cases in this study, the frac plug still enabled some degree of flow resistance to perforation clusters treated in previous frac stages. The resulting backpressure led to some amount of proppant entering all perforation clusters of the non-isolated stage.

1. Design modifications based on vendor standard designs that are not validated to verify performance are susceptible to unintended consequences.

2. The top-performing frac plugs had several distinctive design features: a larger element contact area for better sealing and stability, an optimized setting sequence for secure grip and seal around the tubular, and rigorously tested ball and seat interface for robustness under operational loads.

3. The industry has an opportunity to better align on key performance objectives for composite frac plugs. The top-performing frac plugs are those rigorously tested through specific validation protocols, confirming their effectiveness under realistic downhole conditions.

4. Evaluating frac plug isolation with any single data source proved to be difficult. Clarity is provided when multiple data sources are combined to determine if a frac plug isolated the frac stage.

5. Evidence indicates that most frac plug failures in this trial occurred at the ball-and-seat interface rather than at the exterior of the frac plug. Further design considerations including replacement of ball-and-seat technology should be considered.

6. Full job shutdowns in the middle of the treatment potentially lead to unintended consequences such as loss of treatment isolation and diminished flow into one or more perforation clusters.

7. Frac plugs that maintain their integrity throughout a frac stage demonstrated lower drill-out times and reduced wash times between frac plug locations.

8. As evidenced by perforation entry-hole erosion analysis, isolated frac stages received more proppant and exhibited a higher uniformity index than non-isolated frac stages.

9. It was sometimes difficult to identify non-isolated frac stages by characteristic signatures in the treatment plots.