Case study of mill-out operations in the Permian Basin which evaluate chemical program and processes used. Results show how existing processes and chemicals used or lack thereof, can affect equipment and undo the preventative chemical treatments used during the hydraulic fracturing process. The study looks at field water testing performed during various mill-out operations and considered workover rig vs coiled tubing, equipment set up, water & chemicals used, and operational challenges. Water analyses were completed on injection water and returns at various interval of the mill-out. Effectiveness of chemical treatment was also monitored when biocide was used. Four field case studies are presented for horizontal wells. Two wells were milled-out utilizing workover rigs and two wells were completed using coiled tubing. Testing results show the impact of equipment setup and operations process on the water quality and efficiency of the chemicals used. Water fouling was prevalent in all cases, with coiled tubing jobs showing the highest degree of water contamination and chemical inefficiency. Changes in water treatment program during operations showed significant improvement and sustainable results. Potential corrosion of the work string due to water fouling and composition was also observed, and the effects of changes in chemicals were monitored. This is important because it identified operational improvements that can reduce equipment replacement costs, chemical overuse and protect wells from fouling due to high bacteria. This case study provides a comprehensive review of mill-out operations and provides guidelines for improving chemical efficiency and potential of extending life of the work string.
Data from fluid level shots can be very valuable in optimizing the chemical treatment program. For example, selecting continuous treatment vs truck treatment, adjusting flush volumes on truck treated wells, ensuring slip-streams are open and adequately slipping, or raising the SN depth on wells that cannot be pumped down. Just because chemical is being introduced into the backside does not mean it is effectively getting downhole, or getting downhole at all. This is especially true with flumping wells that are particularly hard to treat without a cap-string (although operators often apply cookie-cutter treatments for the whole field without taking individual well differences into account). Different methods of introducing chemical into the well and ways to overcome chemical treating challenges will be discussed and tied into how data from fluid level shots can help guide better decision making.
Production performance monitoring has existed in Rod Lift Artificial Lift for decades, however there has lacked any action based on performance parameters. The Total Production Real Time (TPRT) Monitoring System incorporates data acquisition with artificial intelligence and automation to provide safer production operations for personnel and environment. TPRT collects live production data at surface on Rod BOPs, Stuffing Boxes, and Rod Rotators then drives actuation based on performance outside of expected performance parameters. For example, when a leak is detected at the primary seal for a Stuffing Box, TPRT engages a secondary actuator to recompress the seal, maintaining environmental control of the well during production as opposed to current product solutions which simply shut off the pumping unit at this minor inflection point on equipment performance. TPRT utilized point-to-point data acquisition and transmission to provide operators with live, cloud-based performance data on remote wells. The core functionality of TPRT is to maximize productivity while protecting from environmental leaks and limiting unnecessary visits to well sites.
With the development of new digital technology over the last several years, our industry has seen many benefits of remote monitoring and automation in sectors within drilling, completion, and production. One area that has lagged is remote monitoring and automation of production chemicals applications. This paper will review initial pilot testing of automated chemical pumps on a group of newly completed wells. The initial objectives of this pilot test were to 1) seek to identify potential chemical cost savings during the early life of the well by autonomously linking chemical injection rates to production volumes; 2) confirm that chemicals are being consistently applied at the prescribed dosages; 3) set up notifications alerting personnel of potential problems, such as low tank volume or inadequate power supply; 4) be able to use the historical chemical tank level data to assist in approval of chemical delivery invoices; 5) determine if operational efficiency of chemical vendor can be improved by needing to check tank volumes and pump rates less frequently; 6) help identify other applications in which this technology could be beneficial such as saltwater disposal chemicals or methanol injection for compressors. Methods, Procedures, Process: Automated chemical pump controllers with built-in communication devices are used to monitor and optimize chemical injection rates. The chemical pump controllers are then able to be remotely monitored and controlled using optimization software. A prescribed dosage target of chemical to production volume is assigned in the software where the software then calculates dosing rate each time a new well test is entered. The software sends the new dosing rate to the chemical controller. We also configured the software to send automated emails to the Well Optimization Analysts and the chemical vendor representatives to alert personnel of low tank volumes or low voltage issues. Results, Observations, Conclusions: The supply voltage would drop so low during the night that the pump would stop pumping. We had to upgrade our solar power system on certain wells to provide enough power to consistently achieve target chemical injection volumes. We then set up low voltage alarms so that we are immediately notified if there is a problem with the system. Also, by remotely monitoring tank levels and alarming on low tank levels we ensure that chemical deliveries are made on time. Another benefit from monitoring and trending tank levels is the ability to use the historical data to assist in confirming chemical invoices. Novel/Additive Information: Chemical programs have historically been controlled manually by a chemical vendor technician or operator on location in a reactive manner. Chemical tanks running dry, the loss of power, and lack of accountability can all be mitigated and resolved by automating chemical injection and enabling remote control.
For decades sucker rod pump artificially lifted wells have used devices called pump off controllers (POC) to match the pumping unit’s runtime to the available reservoir production by idling the well for a set time where variable frequencies drives are not available. In doing this the POC allows the well to enter a set period of downtime when the downhole pump fillage is incomplete to avoid premature failures, and then brings the well back online to operate before production is lost. Although this method has been successful for several years, autonomous control algorithms can be utilized to reduce failures or increase production in cases where the downtime is not already optimized. Optimizing the idle time for a sucker rod pump artificially lifted well involves understanding the amount of time required to fill the near wellbore storage area before generating a fluid column above the pump intake that will begin to hinder inflow from the reservoir into the wellbore. By varying the idle time and observing the impact on production and cycles the program hunts for the optimal idle time. By constantly hunting for the optimal idle time the optimization process can adjust the idle time when operating conditions change. This gives the advantage of always meeting the current well bore and reservoir conditions without having to have a user make these changes and determine what the downtime for the well is. Autonomously modulating the idle time for a well, if done properly will either reduces incomplete fillage pump strokes, in cases where the idle time is too short, or will increase the wells production in cases where the idle time is too long. Overall this will result in the optimization of wells by reducing failures and/or increasing production, generating a huge value to the end user by automating the entire process of downtime optimization.
Variable Frequency Drives (VFD) are a well-known method of pumping beam wells. By running the well continuously and adjusting pumping speed based on pump fillage, they provide unique benefits to reduce failures in difficult environments as compared to operating in pump-off control (POC); these environments might include solids, buckling tendencies at pump-off, and CO2 WAG environments. Although the industry recognizes the VFD benefits, many candidates remain on POC due to the capital investment required for a VFD purchase. This paper discusses two assets within Oxy Permian EOR and analyzes the economics of VFDs in order to assess if expanded usage is justified.
The Apache-operated Adair San Andres Unit (ASAU) currently employs fifteen capillary string (cap string) equipped producing wells, representing 16% of the active producer count. Apache started converting producing wells to cap strings in 2016. This idea was introduced to Apache at the 2012 CO2 Conference in Midland and later reinforced during a field tour of Whiting’s North Ward Estes CO2 flood in 2015. The chief benefit using a cap string is production stability. A review of these installations
is categorized by a reduction in production variance, meaning an increase in stability - be it oil and gas production, or water-oil and gas-liquid ratio (GLR). This equates to less rig intervention, more uptime. Of note: 1) a cap string will successfully operate below the minimum GLR of 400 SCF/BBL/1000’ required by plunger lift, 2) conversion to cap string assisted lift is not affected by the wellbore geometry, and 3) ASAU installations are packer-less.
Electric Submersible Pumps (ESPs) are severely affected by free gas entering the pump, which cause significant degradation in pump performance, due to gas locking conditions cause by bubbles blocking the fluid from passing through the impellers, resulting in frequent shutdowns and restarts, which increase the risk of early failure. This effect is even worst when a gas slug event, very common in horizontal wells drilled in unconventional reservoirs, hit the system, this event consist of a large volume of light density fluid (gas) flowing through the system, overheating the motor and pumps due to a no liquid flow condition, resulting in unstable production due to ESP shutdowns caused by underload or high motor temperature. The industry has used shrouds, rotary and vortex gas separators, and more recently, multiphase pumps to handle the gas, however, there are some applications where this equipment is not enough to handle the Gas Liquid Ratio (GLR). Recently two Oil Operator Companies in the Permian basin following our recommendation successfully installed a multiphase encapsulated production solution technology to separate the gas from the liquid in the wellbore. As produced fluids, pass the pump at high velocity, the heavier liquid falls back into the shroud in a low-velocity area between the tubing and the top of the shroud, allowing the gas to continue to the surface. This system has proven to separate the gas from the liquid effectively (> 90% of efficiency), stabilizing operations within a certain operating window. In this document, results are shown for two successful field cases, how uptime improved, being able to reduce the number of shutdowns, improving operational performance and increase the drawdown maintaining stable production of the wells.
Data from fluid level, dynamometer, pressure, and motor power measurements were acquired by a standalone programmable monitoring system that uses internet and cellphone communication with the Cloud for remote monitoring of well performance. The system named Remote Asset Monitoring or RAM is described in detail in this paper that presents results from the tests that lasted several weeks, beginning with well pump down, just after new pump installation and continuing during normal production operation. The performance of the well was monitored in detail and additional measurements were acquired as needed based on the real time performance of the pumping system.
In the past an operator was required to be at the wellsite to perform these tests. Once the portable RAM system was deployed at the well site and was programmed for standalone acquisition, the well performance trends were monitored wirelessly over extended periods of time without requiring an operator to return to the wellsite.
When connected via the cloud, the data acquisition schedule was adjusted remotely and the stored data was viewed and retrieved as needed. Additional measurements were performed and interpreted in real time so that the operator was able to troubleshoot and analyze the performance of the well from any location in the world.
Failures due to Rod wear and tubing wear account together for an approximate range between 50% to 70% of the OPEX in Rod Lifted systems. Industry has made significant improvements by separating the steel components during their relative movement by using different materials in between them and as sacrifice components. The rod guide is one of them and it comes today in several shapes and compositions. One of those compositions, and the most successful one, is the plastic guide. In the pursuit of the best plastic for West Texas wells, Oxy and Tenaris teamed up to assess Polyketone plastics with varied concentrations of glass fiber and seeking options to reduce the friction factors of this polymer on tubing ID. This paper describes the features in the selected polymer, the different configurations considered, an overall view to the qualification program, key quality assurance steps to comply with Tenaris QMS. Finally, Oxy’s implementation of the guides and the results from the operations. Since March 2020 Tenaris started supplying guides with this polymer to Oxy. To the date of this publication more than 50,000 guides have been installed with zero failures reported.
Water block after hydraulic fracturing is one of the major challenges in shale oil recovery which affects the optimal production from the reservoir. The water blockage represents a higher water saturation near the matrix-fracture interface, which decreases the hydrocarbon relative permeability. The removal of water blockage in the field is typically carried out by soaking the well (i.e., shut-in) after hydraulic fracturing. This soaking period allows water redistribution, which decreases the water saturation near the matrix-fracture interface. However, previous field reports show that there is not a strong consensus on whether shut-in is beneficial in term of production rate or ultimate recovery. Due to the large number of parameters involved in hydraulic fracturing and tight formations, it is challenging to select which parameter plays the dominant role in determining the shut-in performance. Furthermore, literature on field case studies does not frequently report the parameters which are of researchers’ interest. In other words, the challenge of evaluating shut-in performance not only lies on the complexity of parameters and effects involved within the reservoir, but also the limited number of field case studies which report a comprehensive list of fracturing and reservoir parameters.
This paper aims to investigate the effect of well soaking timing on shut-in performance. This question is motivated by the fact that in the field, shut-in can take place either immediately after hydraulic fracturing but before the first flowback (i.e., pre-flowback) or sometime after the first flowback (i.e., post-flowback). The timing of shut-in is believed to influence the production performance, because it dictates how much water will imbibe from the fractures. A numerical core-scale model is built and validated by a successful history match with numerous experimental data. Our model demonstrates that shut-in performed after the first flowback (i.e., post-flowback) can help ensure a higher regained oil relative permeability than shut-in performed before the first flowback (i.e., pre-flowback). A discussion on the water blockage mitigation from these two shut-in timings is also presented. As a result, this study proposes that flowback should be carried out immediately following hydraulic fracturing, even if an extended shut-in is to be performed later.
Surface coatings are commonly used in many industries including oil and gas; with the aim of hardening the part surfaces to improve wear resistance without compromising the corrosion resistance -or even improve when applicable. Sucker rod pumps employ several parts with coated surfaces as well, including the pump barrels. Both standardized surface modifications and specialty applications for pump barrels are readily available in market for different well conditions, including extreme well solids and H2S and CO2 service. These service conditions can be detrimental for pump performance if the right coating is not used. In addition to service conditions, well treatment methods such as acidizing can also deteriorate the coating performance, causing pump failures. This study focuses on the structure of 6 different standardized and specialty coatings on sucker rod pump barrels and an experimental study on their degradation in acidic environments, while familiarizing the reader with the recommended service conditions.
Rod pumping unconventional wells is becoming increasingly challenging due to unpredictable downhole environments. Many unconventional wells exhibit significant deviation accompanied with corrosion making them difficult to rod lift without exposing downhole equipment to unpredictable damage mechanisms – specifically the rod string.
Continuous rod is a proven technology in these deviated unconventional wells as it increases the mean time between failures through lack of connections and distributed side loads. Although continuous rod will increase the mean time between failures, all rod pumping systems will eventually require an intervention. Traditionally, when continuous rod is pulled during a workover, inspections have been done visually in the field by experienced rig crews. However, this method is imprecise and subject to human error. This can result in unexpectedly early failure after a satisfactory inspection or additional cost from replacing mechanically serviceable continuous rod strings.
The Low Voltage – Electromagnetic Inspection (LV-EMI™) unit will detect three-dimensional discontinuities and cross-sectional loss in semi-elliptical and round continuous rod strings. In this paper, the continued development of this new technology and the results from two semi-elliptical continuous rod string scans will be presented. Proposed future enhancements resulting from preliminary field tests will be identified.
When rod pump wells are operated in corrosive environments, corrosion induced sucker rod parts can lead to premature well failure and expensive, repeat workovers. Many corrosion mitigation solutions exist to combat this type of failure, including metallurgy, chemical inhibitor, and epoxy coatings, but they can be costly and not all solutions are appropriate for all types of wells.
In deep wells that require higher tensile rod strength, corrosion friendly metallurgy is generally not an option. In low producing wells, epoxy coatings may not be economically justifiable, depending on lead times and distance from a coating plant. Corrosion inhibitor can require constant monitoring to ensure the treatment is working and not all wells have an environment that promotes an even coating of inhibitor.
In wells where traditional mitigation techniques have not been effective or economic, RodGuard has been successfully used to reduce the frequency of corrosion-induced rod parts.
Success in the oil and gas industry comes with effectively juggling four key elements: money (made or lost), risk, technical capability, and competition. Information is key to managing this process. Data sharing is the controlled process of providing information to and obtaining information from your competitors in such a manner to ensure your success (and theirs, as well). When well executed, data sharing can help one optimally find and develop highly profitable properties with minimal risk for failure. Unfortunately, poorly executed, the data sharing process can tilt the pursuit in the other direction, as well. This paper was prepared to provide the reader with an understanding of the data sharing process and how to effectively leverage information to succeed in such a competitive and technically challenging environment. There are many data sources available, with varying degrees of cost and value. A great deal of data is available for free from public sources, in a variety of formats. There is also an entire industry made up of companies that, for a fee, provide consistent methods to retrieve public data. They also provide value-added services to validate, scrub, and, sometimes, interpret the data. There are also services to find relevant information or, if necessary, to generate data. Each of these methods incurs some cost, whether it be directly financial, in terms of effort, or risk (due to reliability concerns). A great advantage of these methods is that there is no need to release valuable data to one’s competitors. The disadvantage is that a great deal of valuable information is not available via these avenues. This is where data sharing comes in, from consortia to directly sharing with potential competitors. Data sharing can be extremely valuable, not only in obtaining data but also in developing relationships that build information conduits and can lead to profitable operations that can only be pursued with a partner. While there is considerable value to this approach, there are challenges and hazards that need to be navigated. This paper describes the various methods of retrieving, purchasing, and sharing data and how to utilize data sharing as a mechanism to effectively compete in a challenging environment.
Catastrophic accidents in offshore drilling operations have greatly endangered human lives, environment and capital assets. Although risks in offshore oil and gas operations cannot be completely eliminated, a substantial amount of risks can be minimized through preventive and mitigative measures. A key aspect of the offshore drilling risk is the reliability of drilling systems. According to the World Offshore Accident Dataset and many other investigations, the overwhelming majority of disastrous accidents in offshore drilling operations were caused by equipment failures and human errors. The capabilities to predict the lifetime and provide early and effective warnings in real time are crucial to ensure reliable and safe offshore operations. The objective of this research is to mitigate offshore drilling risks by developing a scientific framework for data-driven failure prognosis for complex drilling systems operating in heterogeneous and extremely harsh environments. A novel data-driven reliability model in conjunction with a systems and economic impact analysis is developed integrating multi-source (e.g., operations and maintenance records, in-situ monitoring data) and multi-modal (e.g., lifetime data, degradation profiles) data. Numerical cases studies will be presented to demonstrate the proposed method.
In a reciprocating rod lift application, production tubing failure due to metal-to-metal contact with sucker rod couplings is a common problem in the highly deviated sections of the tubing string. The coupling is forced to be the point of contact against the tubing wall, which causes high friction and excessive tubing wear during the reciprocating motion. This excessive tubing wear typically leads to a hole in the tubing wall, resulting in high workover costs for the producer. The coupling surface hardness, roughness, and coefficient of friction between the coupling and the tubing are all directly related to the resulting tubing wear generated at the contact region. This paper intends to show through both in-house laboratory testing and preliminary field results that applying a lower friction coating to a sucker rod coupling decreases tubing wear and increases the life of the string.
Problem being addressed: Determining optimized Gas Injection Rate for Gas Lifted wells to maximize lift efficiency. Challenges: While Gas Lift is the most natural artificial lift method, ever-changing surface and downhole conditions cause significant inefficiencies. The changing conditions require frequent adjustments to surface-injected gas rates to maintain the most efficient lifting gradient. If the proper adjustments are not made, these inefficiencies may hinder production and increase lease operating expenses. Solution: By using Apergy’s proprietary hunting algorithm, Bloodhound, optimal gas injections rates are determined by the magnitude in the bottom hole pressure drawdown, with use of a permeant down hole gauge. Through continuous and proportional rate adjustment, the Bloodhound algorithm learns from previous set point deltas and tests against the inferred optimal rate, as well as changing conditions. Results: In under-injection scenarios, Bloodhound can accelerate the recovery of oil by up to 10 percent, regardless of the well’s position on its natural decline. In over-injecting scenarios, wells can maintain oil production rates while using up to 50 percent lift gas. Both results can be successfully achieved with few engineering hours, manually calculating or modeling well performance curves to determine inferred optimal rate.
A hydrodynamic analysis for different rod guide designs simulating downhole fluid conditions was made using computational fluid dynamics (CFD) analysis, which is widely used for solving the partial differential equations of fluid motion by discrete approximation. A particular turbulence kinetic energy graphic for each guide sample was created and compared to each other. The results shows a significant difference between the samples and the new rod guide design with conclusive proof of a better hydrodynamic performance.
Dog Leg Severity (DLS) had been used for many decades as recommendations to try to drill oil and gas wells and provide "trouble free" operating conditions. Many of these recommendations were historically based on vertical, shallow (<5000 ft.) deep wells. But as wells continued to be drilled deeper, the recommendations were still applied. With the current drilling and operating practices of deviated and/or horizontal wells, these recommendations may no longer be applicable. Additionally, the deviation measurement interval (degrees/100 ft.) also may no longer be accurate when trying to match downhole problems using existing rod string design software. Furthermore, as wells have become deeper and many now also exclusively are drilled as deviated/ horizontal, side loading (SL) may be a more appropriate condition to be used to determine problems. This paper will review the historic DLS recommendations, provide insight on deviation measurement interval, discuss the importance of SL, and provide new recommendations for drilling wells that should provide better, longer term, less problematic operating wells.
In 2017 and 2018 Oxy EOR conducted a series of RCFA schools. As part of these schools, information was gathered on the range of equipment replacement for failure types. In 2018, a cross functional team of experienced stakeholders vetted this information and compiled a list of equipment replacement guidelines. This paper will share these guidelines.
The Midland Basin teaches a hard lesson in drilling harder rock. SM Energy first drilled there in 2008 before launching a successful horizontal drilling campaign in 2013. This work focuses on a successful application of the limiter redesign process supported with downhole sensors. Whirl suppression generates ROP performance improvements. This objective is complicated with a coupling to stick slip in hard rock applications. High WOB and therefore high torque tends to excite stick slip. Torque oscillations start, speed oscillations follow, and result in inconsistent DOC. Bit forensics on large wear flat shoulder cutter wear and delamination indicate high speed, friction, and heat damage under these conditions. This problem is explored in depth across the interbedded intermediate section of three pilot wells within the operator’s southern Midland Basin acreage. All three wells were drilled in a single bit run to TD and successfully cased and cemented by design. Three high frequency sensors recording at 100 Hz were installed in each BHA – one located in the bit, above the drilling motor, and at the drill collars. High frequency surface measurements were successfully tied to subsurface sensor observations. Good wellbore trajectory design, high ROP, and low planned dog leg severity positively contributed to weight transfer exceeding +97% based on WOB measurements in the BHA. Autodriller setpoint control and tuning unlocked ROP gains between 20-40% in the shallow hole section. MSE is reintroduced. Its practical value in baseline drilling surveillance and benchmarking is confirmed. The first well is treated as the control in the project. The trial starts with the common bit and BHA for the area with planned parameter step tests performed in each significant formation group. The second and third wells repeat the same workflow with progressive BHA changes to a single component. Depth of cut control is designed and utilized successfully on these wells to reduce torque oscillation. Roller reamers implemented on the final well act as a low torque stabilizer to increase useful torque at the bit. Torque stabilization and minimizations strategies must be paired with sufficient drill string stiffness to maximize performance impact in high WOB applications. The drilling performance initiative outlined in this paper is meant to be accessible to all drill teams and a call to action to redesign problems to the economic limit, forever.
With the increase in the number of horizontal wells drilled in the past 15 years, the technology for predicting downhole conditions and troubleshooting problem wells has not kept up with the increased complexity of these deeper and deviated wellbores. The systems in use are no longer accurate or sensitive enough to determine what is causing the problem(s) resulting in shorter meantime between failure and higher workover cost to the operators. To unravel the mystery we introduce the Downhole Sucker Rod Sensor which measures what is happening downhole and enables the customer a systematic approach to troubleshooting and therefore reducing the number of failures while providing a method for measuring the effectiveness of new and existing technologies. These sensors can be strategically placed anywhere in the rodstring and collect high-resolution measured data for pressure, temperature, torque, compression, velocity and position. In addition to generating a high resolution measured downhole DynaCard that can distinguish sync issues with different strokes per minute (SPM). The data is used to uncover issues with string wear i.e. alignment or sync issues, friction, pump and tubing issues as well as calculated values for specific gravity, pump fillage, and pump intake pressure. The main objectives are summarized as follows: o Comparing actual Downhole DynaCard measurements to the Surface and the Predicted Cards o Maximizing reservoir drainage and production optimization o Identifying, isolating and optimizing mechanical issues in problem wells o Measuring the impact of new and existing technologies (such as guides, friction reducers, …) and their effectiveness in extending the service life of the SR system. o Verify if rod guides, friction reducers… are adding value and not just cost! Vision: o Utilize sucker rod sensor(s) on problem wells and convey lessons learned to other wells. o Improve the software systems currently calculating downhole dynagraphs. o Improve the accuracy of (surface) software calculations which will yield improvements for a large number of unconventional wells. o Provide our Customer’s with a competitive advantage.
The purpose of this project is to conduct a Dynamic Filtration Test to Investigate the Effect of Preformed Particle Gels (PPGs) on Un-swept, Low-Permeable Zones/Areas. A filtration test is a simple means of evaluating formation damage. This work use schematically dynamic filtration test experiment design apparatus to carry out the various filtration test experiments. It use different core samples, various brine concentration, and various gel types. The permeability of each sandstone core samples is calculated before and after the filtration test. Experiments are still being observed. The objective of this study is to find methods that minimized the damage caused by PPGs on un-swept, low-permeable zones/areas, thus improving PPG treatment efficiency. This approach will identify the best properties of the PPGs, which can neither penetrate conventional solid rocks nor form cakes on the rocks’ surface.
Friction reducer is a hydraulic fracturing fluid additive meant to lower costs by decreasing the friction pressure in tubulars during pumping operations. High viscosity friction reducers (HVFRs) have become increasingly popular in well stimulation applications in lieu of conventional slick water fluid systems involving linear and cross-linked gels. However, various factors must be considered when assessing the effectiveness of using HVFRs under certain frac operation conditions. This paper aims to evaluate how effective of a solution HVFRs are while determining the optimal operating conditions for this additive.