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Collaborating Authors
OnePetro
Experimental Investigation Using Low-Frequency Distributed Acoustic Sensing for Two Parallel Propagating Fractures
Reid, T. (Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, TX, USA) | Li, G. (Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, TX, USA) | Zhu, D. (Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, TX, USA) | Hill, A. D. (Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, TX, USA)
Abstract Low-frequency distributed acoustic sensing (LF-DAS) is a diagnostic tool for hydraulic fracture propagation in the far-field using measured values of strain. To understand subsurface conditions with multiple propagating fractures, a laboratory-scale hydraulic fracture experiment was performed to simulate the LF-DAS response to fracture propagation with embedded distributed optical fiber strain sensors under these conditions. The objectives of this research are to generate two hydraulic fractures of known geometry, measure the strain response along distributed fiber sensors embedded in the sample, and use the results to improve interpretations of field LF-DAS data when multiple fractures are approaching an observation well. The experiment was performed using a transparent 8-inch cube of epoxy with two-parallel radial initial flaws centered in the cube 2.6-inches apart. Fluid was injected into the sample to generate fractures along the initial flaws. The experiment used distributed high-definition fiber optic strain sensors with tight spatial resolutions. The sensors were embedded at two different locations on opposite sides of the initial flaws, serving as observation/monitoring locations. Pressure and fracture propagation were also recorded. This paper presents a workflow to model fracture geometries, and simulate the resulting strain along a fiber optic sensor. We employed finite element modeling to numerically solve the linear elastic equations of equilibrium continuity and stress-strain relationships. The simulation domain includes one-half of the 8-inch epoxy cube with two radial fractures. The measured strains from the experiment were compared to simulation results from the finite element model. The experimentally derived strain and strain-rate waterfall plots from this experiment show responses to both fractures propagating, while the fracture below took most of the fluid during the experiment. Interestingly, a fracture first began propagating from the upper of the two flaws, but once the lower fracture was initiated, it grew much more than the upper fracture. Both fibers were intercepted by the lower fracture, further verifying the strain signature as a fracture is approaching and intersecting an offset fiber. The zero-strain-rate method was applied to both fibers to dynamically estimate the propagation of the fracture fronts as they approached the fibers. The fracture growth behavior interpreted with the zero-strain-rate method compared well to the evolving fracture dimensions obtained from video-recording of the fracture geometries. The results from this work can be used in the field to reveal stress shadowing effects of two fractures and further increase our understanding of how LF-DAS can be used in the field to diagnose fracture propagation when multiple fractures are approaching an observation well.
Abstract One of the challenges encountered in hydraulic fracturing of unconventional resources is casing deformation. Casing deformation statistics vary across different regions of the world, but it is estimated to affect 20-30% of horizontal wells in some areas of operations. The consequences of casing failures can be varied but, in many cases, it affects the well production, wellbore accessibility and in some rare instances presents a situation of well control and its associated risks. Incidentally, most literature on casing deformation pertains to "plug & perf" fracturing operations in cemented completions though pipe deformation is known to occur in multi-stage fracturing (MSF) sleeves type of openhole completions as well. Intuitively, the two failure mechanisms may appear similar instead they represent very diverse well conditions that lead to pipe deformation. Tubular damage during fracturing is not caused by a single, consistent reason. Multiple mechanisms may be responsible for casing deformation; formation rock properties, wellbore configuration, cyclic loads acting on the tubulars, tubular quality, cement bond, or simply some operational aspects during drilling and completion conducive to pipe deformation. Tubing stresses analysis of the lower completion and especially of the individual components of the openhole MSF completion is seldom done. A comprehensive study was initiated by first validating the key data and parameters, multi-arm caliper data in conjunction with downhole camera imaging, and review of the physical mill-out patterns of frac plugs (in cased hole completions) and ball-seats used in MSFs to understand the damage pattern. This work was supported by detailed geo-mechanical properties profiles, diagnostic injection tests analysis, and evaluation of casing integrity under anticipated fracture loads. One of the primary learnings from this study was that wellbore quality had a significant bearing on the post-frac wellbore integrity for both types of well completions. The study indicated that well profile, design, and tool placement in the well also had a strong influence on axial load distribution in open-hole multistage completions. The mode of failure in openhole multistage wells was different than those seen in cemented liners. These differences do not necessarily fall under the domain of formation movement experienced in geomechanically complex and tectonically active areas. Since reservoir uncertainties are a reality, a good wellbore quality cannot always be guaranteed. It becomes necessary to manage pipe deformation with mitigating practices. This paper provides practical solutions to pipe deformation in cemented and openhole completions. The operational workflows allow upfront assessment with analytical tools to model the stress loads. By understanding the primary factors that affect well integrity, the likelihood of casing failure can be predicted and avoided ahead of time, save fracturing costs across high-risk areas, and not jeopardize production from multimillion-dollar completions. Managing well integrity is essential for development of hydrocarbon resources while preserving the environment and assuring safety of personnel.
- Asia > Middle East (0.68)
- North America > United States > Texas > Harris County > Houston (0.28)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Loma Campana Field > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Loma Campana Field > Lower Agrio Formation (0.99)
- (2 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Well Integrity > Zonal isolation (1.00)
- (4 more...)
Optimization of Enhanced Geothermal System Operations Using Distributed Fiber Optic Sensing and Offset Pressure Monitoring
Titov, A. (Fervo Energy Company, Houston, TX, USA) | Dadi, S. (Fervo Energy Company, Houston, TX, USA) | Galban, G. (Fervo Energy Company, Houston, TX, USA) | Norbeck, J. (Fervo Energy Company, Houston, TX, USA) | Almasoodi, M. (Devon Energy Corporation, Oklahoma City, OK, USA) | Pelton, K. (Devon Energy Corporation, Oklahoma City, OK, USA) | Bowie, C. (Devon Energy Corporation, Oklahoma City, OK, USA) | Haffener, J. (Devon Energy Corporation, Oklahoma City, OK, USA) | Haustveit, K. (Devon Energy Corporation, Oklahoma City, OK, USA)
Abstract Enhanced Geothermal Systems (EGS) have emerged as a promising method to generate electricity from geothermal resources in areas that lack natural fractures and/or faults needed to connect injector/production well sets, virtually eliminating dry hole risk. EGS leverages much of the learnings from the past two decades of unconventional developments, connecting horizontal wells with multi-stage stimulations to create connectivity to flow water between wells to mine heat from the subsurface. This paper presents a case study in measuring EGS fracture geometry, utilizing measurements from vertical and horizontal permanent fiber optic cables and offset pressure monitoring. The Devon Quantification of Interference (DQI) analysis is also applied to multi-stage stimulated geothermal wells, integrated with fracture and reservoir simulation. Fervo Energy, a first mover in EGS, is leading the way in developing this technology. Devon, an industry leader in unconventional oil and gas development, leverages their learnings in this field to optimize EGS operations. Optimal well spacing and completions design, much like in oil and gas, are critical to optimizing for a successful EGS development. Analysis of strain rate in offset well and multi-well microseismic recorded with fiber optic cables during stimulation and well testing allowed to characterize stimulated reservoir volume created by hydraulic stimulation and optimize well placement. The DQI analysis examined the well-to-well connectivity of the multi-stage stimulation between the two wells in the case study, providing insight into the conductive fracture geometry. The paper also discusses the execution of well preparation, stimulation, and high-level well performance. This study provides valuable insights into the development of EGS using vertical and horizontal permanent fiber optic cables and offset pressure monitoring. The findings suggest that this approach can be effective in optimizing EGS operations. Fervo Energyโs expertise in EGS development, combined with Devonโs expertise in unconventional oil and gas development, can be leveraged to further advance EGS technology at scale and generate electricity from geothermal resources. This paper serves as a valuable resource for operators looking to optimize EGS operations.
- Overview (0.48)
- Research Report > New Finding (0.34)
- Energy > Renewable > Geothermal > Geothermal Resource (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource for Power Generation > Enhanced Geothermal System (0.61)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Non-Traditional Resources > Geothermal resources (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract Continuing from the previous publication (Navaiz et al. 2023) detailing the hydraulic fracturing energy system and energy transfer as fluid and proppant are pumped from the surface into formation. this paper focuses on the validating the importance of effective energy delivered to formation and its correlation to total productivity. Combining extensive in-house pumping data and well-production data available from the public domain, a two-dimensional approach cross-plotting total effective energy injected per unit area against production output shows a highly correlative positive relationship (R2>0.75) across several basins in North America. This strong relationship not only reinforces the value of this energy analysis concept in hydraulic fracturing established by the authors previously. It also validates the conservation of energy principle highlighting the usefulness of relating effective energy injected into formation to a direct increase in reservoir energy potential and therefore a greater potential for total productivity. With the unconventional oil and gas industry highly focused on capital efficiency, the effective energy metric enables near-instantaneous optimization of development costs rather than iterating on 6-month or 1-year production performance. Time and capital can then be invested in technologies and processes that maximize effective energy and resultant productivity or minimize energy losses in the system.
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (36 more...)
Evaluation of Fracture Stimulation Performance Based on Production Log Interpretation
Li, Gongsheng (Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, Texas) | Sakaida, Shohei (Chevron Corp) | Zhu, Ding (Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, Texas) | Hill, A. D. (Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, Texas) | Kerr, Erich (SM Energy Company, Houston, Texas)
Abstract Production logging is a traditional approach to monitor an inflow profile in a hydraulically fractured horizontal well. By quantitatively interpreting production logs run in a hydraulically fractured horizontal well, we can evaluate and optimize fracture stimulation design. This paper presents a field example of completion analysis based on production log interpretation. In this well, the fracture treatment design was varied by stage to examine which completion parameters are more influential on productivity. The production performance for each stage was evaluated using an array of spinner flowmeters and phase holdup-sensing devices, and a temperature log. Multiple-sensor array tools were used to measure the phase holdup and local fluid velocity along the wellbore. The cross-sectional area of the wellbore was divided into five segments. The phase distribution of gas, oil, and water within each wellbore segment was assigned based on the phase holdup values along the wellbore. The array spinner flowmeters provided the local velocity inside each wellbore segment. This paper presents a methodology for using data from array production logging tools to interpret the volumetric flow rates of each phase at each interpretation point along the wellbore. The differences in these wellbore phase flow rates provide the downhole inflow distribution along the hydraulically fractured horizontal well. Temperature logs can reveal fluid entry locations as the places where temperature anomalies caused by Joule-Thomson effects occur. When gas is produced, the Joule-Thomson cooling effect as the gas expands in the near-well region generates a cool anomaly that locates the gas entry location. In some cases, the Joule-Thomson heating effect caused by liquid production identifies liquid inflow locations. By performing a temperature history match using a thermal simulator, we quantitatively obtained the gas inflow rates at each active cluster location. This paper demonstrates that the temperature log interpretation provides the inflow profile along the experimental well based on the cooling anomalies. Once we confirm that the inflow profiles estimated by the interpretation of the array production logging tool and the temperature log are comparable to each other, we evaluate the fracture stimulation design based on the production performance for each stage. We present the effect of statistically significant fracture design variables on stage production performance derived from the production log interpretations.
- North America > United States > Texas (1.00)
- Asia (0.68)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (7 more...)
In-Basin Sand Performance in the Permian Basin and the Case for Northern White Sand
Malone, M. R. (New Auburn Energy Management, LLC., Houston, TX, United States of America) | Bazan, L. W. (Bazan Consulting, Inc., Houston, TX, United States of America) | Eckart, M. J. (Bazan Consulting, Inc., Houston, TX, United States of America)
Abstract Proppant selection, and the resulting dimensionless fracture conductivity, impacts well performance. Proppant quality standards were developed to quantify proppant performance using dimensionless fracture conductivity, correlating the flow potential of the propped fracture relative to the formation. Since 2018, there has been a near complete switch to in-basin sand (IBS) for completing oil and gas wells in the Permian Basin. The switch to IBS has primarily been based on the idea that overall well and field economics are improved because: 1) capital costs are lowered by sourcing sand locally reducing costs and logistics, and 2) well results using IBS were "good enough" in terms of well performance justifying the use of inferior proppants. Little regard is given to the long-term production impacts, field development value and cumulative free cash flow over a five-to-ten-year horizon. Rystad Energy (2022) evaluated 850 wells from seven operators in both the Midland and Delaware basins and provided clear evidence that the perceived benefits of using IBS to complete Wolfcamp A (WCA) wells in the Permian is not accurate. The Rystad Energy studies will be reviewed in detail. This manuscript presents extensive hydraulic fracture modeling and production simulations of the WCA formation for both the Delaware and Midland basins using 100- and 40/70-mesh to identify the conductivity difference between IBS and NWS to provide an engineering basis for the Rystad Energy results. Conductivity differences for each mesh and sand type ultimately allowed a comparison of well production and net cash flow for P50 wells. The WCA production forecast cases were calibrated to the published Rystad Energy data, where possible, and EUR values. The payout, cumulative production differences and net cash flow are presented comparing IBS and NWS materials. Comparing results between NWS and IBS provides an engineering basis that NWS characteristics drive superior well performance in the Permian basin. As fracture conductivity increases, either from using NWS material or larger mesh sizes, the well production also increases over time. This is also the general conclusion from the Rystad study. This work demonstrates that NWS, while more expensive upfront, performs better throughout the well life, and is almost always the better economic choice and shows a long-term benefit using NWS. Utilizing IBS in the Permian basin results in suboptimal cashflow and reduced long-term profitability. The well performance using IBS is expected to progressively worsen over time. This work demonstrates fractures in the Permian basin are conductivity limited and using IBS negatively affects cash flow and long term well deliverability. NWS is a superior product to IBS and generates enhanced fracture conductivity and production in the Delaware and Midland basins.
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Geology > Mineral (0.46)
- North America > United States > Texas > Permian Basin > Midland Basin > Wolfcamp A Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.94)
- (26 more...)
Abstract Hydraulic fractures tend to propagate in a plane that is perpendicular to the least principal stress. As a result, unconventional oil and gas wells are typically drilled in the direction of minimum horizontal stress (Shmin) to maximize drainage area. However, in some regions, due to acreage constraints, wells are drilled to maximize the number of wells instead of the ideal orientation with respect to subsurface stresses. We studied the impact of changing well orientation on well productivity in the Bakken Play by simulating a wide range of operational scenarios including proppant loading, well spacing, cluster spacing, and depletion. Our simulation results were compared to historical Bakken well performance data filtered based on the same well orientations and completion designs. The simulation results show that drilling wells parallel to Shmin maximizes well productivity, consistent with the reported actual data. However, the degree of production uplift in actual data cannot be fully attributed to well orientation. We demonstrate that job size, depletion, cluster spacing, and well spacing all affect the impact of well orientation on performance. It is challenging to rigorously quantify the effect of well orientation versus completion design on well productivity in historical data. Simulation studies help to determine the impact of each parameter, helping operators optimize their development strategy. Simulation sensitivity analyses show that depletion, wider cluster spacing, and wider well spacing can lessen the effect of well orientation on well productivity.
- North America > United States > North Dakota (0.49)
- North America > United States > South Dakota (0.35)
- North America > United States > Montana (0.35)
- (2 more...)
- Research Report > Experimental Study (0.49)
- Research Report > New Finding (0.49)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.98)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.98)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.98)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
A Successful Acid Fracturing Treatment in Asphaltene Problematic Reservoir, Burgan Oilfield Kuwait
Al-Shammari, A. (Kuwait Oil Company, Kuwait) | Sinha, S. (Kuwait Oil Company, Kuwait) | Sheikh, B. (NAPESCO, Kuwait) | Youssef, A. (NAPESCO, Kuwait) | Jimenez, C. (Kuwait Oil Company, Kuwait) | Al-Mahmeed, F. (Kuwait Oil Company, Kuwait) | Al-Shamali, A. (Kuwait Oil Company, Kuwait)
Abstract The Burgan Marrat Reservoir is a challenging high-pressure, high-temperature carbonate oil reservoir dating back to the Jurassic age. This specific reservoir within the Burgan Field yields light oil, but it has a significant issue with Asphaltene deposition in the wellbore. Additionally, its well productivity is hampered by low matrix permeability. Addressing these challenges is crucial, and a successful acid fracturing process can not only enhance well productivity but also address Asphaltene-related problems. This study delves into a comprehensive methodology that was employed. The focus of well selection was on ensuring good well integrity and maintaining a considerable distance from the oil-water contact (OWC). The approach involved conducting a Multi-Rate test followed by pressure build-up to establish a baseline for understanding the reservoir's behavior, including darcy and non-darcy skin. The treatment design aimed at better fluid loss control and initiating highly conductive fractures in the reservoir. Specific measures, such as using suitable diverters and acid, were employed to maximize the length of the fractures. To validate the approach, a nodal analysis model was fine-tuned to predict how the well would perform under these conditions. The results post-stimulation were impressive. There was a substantial improvement in well production and flowing bottom hole pressure. In fact, the productivity index of the well increased significantly, representing a substantial enhancement in output. The pressure build-up test after the fracture demonstrated a linear flow within the fracture, indicating a successful treatment with a fracture half-length of approximately 110 feet and a negative skin, which signifies an improvement in flow efficiency. Furthermore, the treatment effectively mitigated the risk associated with Asphaltene deposition, a significant accomplishment given the historical challenges faced in this reservoir. This success can be attributed to an innovative workflow that incorporated a meticulous surveillance plan, a well-thought-out fracturing treatment design, and the application of advanced nodal analysis. Together, these components not only optimized the well's performance but also paved the way for the development of similar high-pressure, tight carbonate reservoirs. This approach not only enhances productivity but also ensures successful mitigation of Asphaltene-related issues, marking a significant advancement in reservoir engineering techniques.
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (15 more...)
Unconventional Reservoirs: Contact Area and Fracture Network Resulting from Perforations in Shale. A Comparative Study of Different Shale Targets and Shaped Charge Designs Optimized for Hydraulic Fracturing
Loehken, J. (DynaEnergetics Europe GmbH, Troisdorf, Germany) | McNelis, L. (DynaEnergetics Europe GmbH, Troisdorf, Germany) | Yosefnejad, D. (DynaEnergetics Europe GmbH, Troisdorf, Germany) | Will, D. (DynaEnergetics Europe GmbH, Troisdorf, Germany)
Abstract After decades of a continuous improvement of the plug and perf technology for horizontal wells and especially the shaped charges employed, operators nowadays have the choice between a variety of shaped charge designs. As a guidance to choose the optimal charge, this snapshot examines the influence of shale rock type and shaped charge design on the tunnel created in the reservoir rock during perforation. Tests were conducted in an API Section II Test environment, simulating in-situ downhole conditions. Specifically, the investigation focused on the characteristics of the contact surface and the induced fracture network resulting from different perforation charges, each with its own distinctive tunnel geometry. Three different shaped charge designs were tested on various shale targets. This included equal entrance hole charges, maximum formation contact, and oriented perforation tailored charges. To assess the impact of the formation rock on the results, test shots were made on Marcellus, Mancos, and Lotharheiler, which is similar to the Haynesville or Eagle Ford, shale cores. The analysis included CT scans to identify tip fractures and to examine the shape of the tunnel as well as conventional core analysis. Additionally, newly formed fractures within the rock and on the surface of the perforation tunnel were identified. The test results indicate that both the charge type and the rock type significantly influence the tunnel geometry and fracture network. Although all charges created roughly the same entrance hole diameter in the casing, variations in tunnel length and contact surface as well as in the newly created fractures were observed. Notably, the shape of the tunnel deviated strongly from the theoretical assumed cylindrical or conical tunnel. Doglegs, as well as cavities were detected at many tunnel tips, which change the overall stress field at the tunnel wall. To determine which rock parameters are relevant, the cores underwent analysis in an external laboratory to assess their petrophysical properties for further correlation analysis. From a practical perspective shale rock proved to be a challenging target rock due to its high anisotropy and significant differences in rock strength between targets of the same formation. Additionally, the target cores were prone to cracking during the rock preparation process. Therefore, this study should be considered as a snapshot and conclusions drawn from this set of tests should be approached cautiously and account for these circumstances. Our study provides insights into the dependency of the perforation result on the type of shale and charge design. Depending on the combination of the perforation technique and the characteristics of the rock formation, distinct fracture networks and tip deviations are formed. This improved understanding will help to identify the best perforation strategy tailored to the specific reservoir rock's unique properties.
- North America > United States > Texas (1.00)
- Europe (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (18 more...)
Abstract The use of synthetic high viscosity friction reducers (HVFRs) has become common practice in hydraulic fracturing as a reliable method for delivering proppant into target formations. HVFRs address many of the challenges that are present when using cross-linked or linear gels and provide reliable performance across a wide range of water qualities. Despite these advantages, HVFRs present their own difficulties that must be addressed. The use of oxidizing or enzymatic breakers is essential when cross-linked gels are used for proppant transport to reduce the fluid's viscosity to a point where formation pressure is sufficient to allow the well to produce, and to minimize formation damage. While HVFRs are not nearly as viscous as cross-linked gels, they have sufficient molecular weight and are viscous enough, and persistent enough, to negatively impact flowback when a well is brought online. Moreover, it has been found that synthetic polymers can also cause serious formation damage similar to or worse than gel-based systems resulting in negative effects on the well's production. As a result, breakers are also commonly used in conjunction with HVFRs to maximize production of the well after stimulation is complete. It is difficult to know if these treatments are effective, however, and are largely guided by prior experience. Such reliance can be dangerous, however, given that HVFRs can comprise a wide range of chemical compositions, molecular weights, and physical forms. We believe a more systematic study of breaker effects on HVFRs is warranted to develop a better understanding of how combinations of breakers and HVFRs should be applied in field operations. Here we will discuss a series of laboratory investigations conducted to understand how different types of HVFRs respond to treatment with various breakers. The breakers selected are chemically distinct and may operate via different mechanisms (e.g., oxidative, non-oxidative), or on different timescales (e.g., instantaneous, slow release). Likewise, the HVFRs are comprised of distinct polymer backbones, and thus we anticipate will behave differently when exposed to the breakers. Indeed, significant differences in viscosity reduction behavior are observed depending on the HVFR-breaker pairing, concentrations of the two components, and test temperature. Some findings were unsurprising, such as the broad applicability and rapid response of instantaneous oxidative breakers, while others were not, such as the relatively selective and temperature-dependent response of non-oxidative breakers. Such a diversity of breaker chemistries and response behavior may initially seem overwhelming for completion engineers designing a stimulation pump schedule. However, we believe that this diversity may, in fact, present an opportunity for more nuanced treatments (i.e., break profiles) through judicious selection and application of breaker and HVFR combinations, all within the context of a well's characteristic temperature and water chemistry.