After deep analysis of gas separation methods and understanding the nature of fluid and gas flow, a new design is developed to generate better downhole conditions and enhance gas separation efficiency. A study of legacy downhole gas separators using a substantial database of horizontals wells across the Delaware and Midland basins demonstrated a decrease in gas separation efficiency with an increase in GLRs and fluid rates. The development of this new methodology breaks the curve, not following the typical relationship of gas rates and gas separation efficiency. This has allowed for meeting and exceeding both rates and GLRs during ESP and Gas Lift to Rod Pump conversions in 5.5” casing, where annular space has previously limited gas separation efficiencies with legacy technology. This new design has an innovative technique to combat surges and homogenizing wellbore fluid to create maximum gas separation resulting in optimal well performance.
 

The installation of tubing in a well makes it susceptible to wall loss from corrosion and wear. This degradation is influenced by environmental conditions, such as temperature, pressure, corrosiveness, and flow rates, along with operating factors like the type of artificial lift and well deviation. Periodic evaluation of tubing condition throughout the well's operational life, using non-destructive testing (NDT) methods, is a recognized best practice. Common NDT methods include ‘scanning’ tubing at the wellhead during a workover or transporting tubing to a specialized facility for comprehensive inspection. The inspection equipment, whether used at the wellhead or in a facility, typically incorporates electromagnetic inspection (EMI) technology to identify defects and assess the tubing’s suitability for continued use. Wellhead and in-facility inspection methods each offer distinct advantages. However, our recent trials demonstrated that in-facility inspections can integrate some benefits traditionally exclusive to wellhead scanning. This development enhances the overall merits of in-facility inspections, establishing it as the preferred method. 

Historically, tubing inspections performed at a facility did not capture the data benefits associated with a depth-correlated inspection enabled by wellhead scanning. An innovative approach adopted to bridge this data gap incorporated a systematic numbering system implemented as tubing is laid down prior to transport to the inspection facility. Once the tubing has been inspected at the facility, the inspection results of each joint are digitally rearranged according to the order they were pulled from the well. The result is a simulated depth-based inspection where the data is then used to create a well profile. This useful graphical tool aids in downhole troubleshooting, failure analysis, and design optimization. 

In addition to the depth-based benefit that is now equalized between both inspection methods, further advantages of in-facility inspections have been obtained. The potential limitations in quality and comprehensiveness due to environmental factors of wellhead scanning conducted during well interventions will be explained. Alternatively, in-facility inspection occurs in a controlled setting under optimal conditions. This allows for comprehensive end-to-end examinations, incorporating EMI and additional inspection techniques. Such thorough assessments are pivotal in detecting subtle yet critical tubing imperfections, enabling a more comprehensive evaluation of tubing integrity. This approach not only enhances the detection of current issues but also facilitates the development of proactive maintenance strategies and well design improvements. 

A thorough inspection at the facility with depth correlation provides accurate data to adjust well design and operation. This has led to an increase in both well run time and material recovery when tubing is inspected following these changes. The details of this process and the impact of this practice on well performance will be discussed. 

The Greater Elk Hills Area boasts a substantial continuous rod population, introduced to the field due to loading requirements and casing restrictions. However, the existing continuous rod population is now comprised of older worn rod strings, with many of these strings exceeding ten years of service. These rod strings commonly require sections of rod replaced when they are pulled during service operations, highlighting the need for a precise and reliable inspection method.  

In the past, visual inspection was utilized to assess the condition of continuous rod strings, determining when worn or corroded sections required replacement. This method is often imprecise and dependent on the rig operator’s expertise. In California Resources case, they were often encountering repeat failures after pulling the rod string to get the well back online. One barrier to widespread continuous rod adoption has been the inability to clearly identify and replace sections of corroded or damaged rods. In the past, when continuous rod was pulled during service operations, visual inspections sometimes resulted in defective rods being rerun, subsequently causing premature and repeated rod failures.  
In 2020, electromagnetic inspection (EMI) technology for continuous rod was introduced to the industry with the Low Voltage Electromagnetic Inspection (LV-EMI™) unit. This unit allows for continuous inspection of the rod while it is being pulled out of the wellbore during service operations. By utilizing this unit, compromised continuous rod sections are accurately identified and replaced, minimizing failures, and optimizing wellbore performance.  Since initial deployment, several advancements have been made to the LV-EMI™ unit, further refining its capabilities, and expanding its potential applications.

California Resources took proactive steps by incorporating EMI scanning into workovers, employing specific criteria to guide their approach. The results of the approach they implemented, along with the lessons learned are presented in this paper. 

A discussion of Rod Lift VSD control parameters, setup, and configuration for optimal operation under varying operating conditions
History shows that many operators utilize only the most basic control parameters when setting up VSDs for rod lift applications. This paper will discuss the VSD and Rod Pump Control parameters necessary for safe, reliable, and efficient rod lift control.    

In gas slugging conditions, conventional gas separators struggle to process and deliver liquid to the pump due to extremely high concentrations of gas within the separator. A prototype slug mitigation system replaced a conventional, high flow, tandem gas separator system in a slugging well. The initial field trial results are discussed in this paper.

This paper builds upon last year's presentation, which featured a case study showcasing the application of gas handling technology in the Midland Basin. With over 200 installations in the Permian Basin, this document expands on the insights gained from various applications, providing additional data that reinforces the operational principles and results presented in the previous year. In this paper, we delve into the intricate physical principles governing the gas handler's functionality in regulating free gas flow before reaching the ESP intake. Through the presentation of three case studies, we illustrate how these adjustments have significantly enhanced project profitability.

The first case study examines a Delaware well completed in the Bone Spring, notorious for historical gas and sand challenges. The regulator was installed alongside the second ESP, with an expected liquid production of 1,200 BFPD and a GLR of 1,000 SCF/STB. The second case study focuses on a well completed in the Middle Spraberry producing 375 BFPD and a GLR of 800 SCF/STB. Considering the production rates, a rod pump conversion was contemplated. The final case study explores a well also completed in the Middle Spraberry, producing 370 BFPD and a GLR of 2,400 SCF/STB with a history of sand and gas issues. Initially considered for gas lift conversion, the lack of facilities led to the reinstallation of the ESP to postpone the conversion to a rod pump and maintain higher production. In all case studies, we evaluate sensor parameters, presenting the before-and-after scenarios of production rates and drawdown.

The purpose of this paper is to present a solution to the adverse impact of fallback sand and debris on ESPs (Electrical Submersible Pumps). When these solids accumulate on an ESP during operational shutdowns, it poses a significant risk of damage and subsequent failures upon restarting the system. The problem arises when the friction force that the motor is required to overcome exceeds the material strength of the motor shaft. This large increase in amperage damages the motor and drive shaft of the ESP.

Installing a Fallback Filter directly above the ESP efficiently captures and reintroduces accumulated solids while maintaining the ability to inject through the ESP.

Many oil and gas companies rely on natural intelligence, resident knowledge, and rules-based logic to optimize production. This is especially true for fields where electric submersible pumps (ESPs) make up a considerable proportion of production on artificial lift. The nature of ESP artificial lift systems makes them well suited for greater remote monitoring, enhanced automation, and implementation of machine learning for autonomous optimization. Extensive use of electric surface controls integrated with downhole sensors provide an ideal operating environment to implement Artificial Intelligence (AI) to achieve autonomous full self-pumping (FSP) operation. However, most operating companies stop short of using automation and machine learning to its full potential. 

This paper will present a case study of an autonomous full self-pumping ESP artificial lift system operating multiple wells in the Permian Basin. The paper will discuss key learning points on how to effectively lead change ensuring field operations and continual innovation are set up to enable success. The overarching goal of the paper is to assist operators in their digital journey by avoiding mistakes in system design and field implementation.

The case study will provide a summary of,
• A field-tested autonomous ESP operating system outlining key components and capabilities. 
• Specialized automation and instrumentation technologies including control and regulation equipment, chemical pumps, and “edge” devices. 
• Developed digital solutions including remote monitoring and autonomous production optimization. 
• Deployment methods to gain acceptance of field personnel and support change management.
• Collaboration of the operating company, ESP supplier, third party partners. 
• Steps to address challenges pumping unconventional wells including rapid decline rates, limited number of field personnel, inconsistencies and biases in optimization tactics, prioritization of uplift opportunities, competing incentives, and uplift vs. ESP run life balancing.

The results of the case study will include,
• Operational benefits including enhanced optimization of ESPs setpoints, improved utilization of personnel, solution scalability, and operational adaptability which favorably impact production, up-time, and run life.
• Development of additional skillsets necessary to supervise autonomous operations.
• Key learnings for successful implementation and continual innovation. 
• Collaboration necessary to break down barriers that can exist between operators, equipment suppliers, and third-party partners. 
• Alignment needed to foster a culture of innovation and “fail forward” mindset; enhanced methods discovered through iteration and continuous improvement.
• Additional benefits including deeper insights into production operations, ESP system technology and software development.

Initial lifting new wells with high pressure gas lift valves when BHP and PI are at the highest to achieve a deeper point of injection, thus higher fluid rates. Converting to normal pressure gas lift when production rates are lower utilizing the balance-ported valve. Balance Ported Valve is a gas-lift valve that allows full, available gas injection pressure to be used for the unloading and operating valves. Using full injection pressure allows for a deeper point of gas injection, which lowers the FBHP, thereby increasing production. With standard IPO valves, it is necessary to design the valves with casing pressure drops in order to close the valves as the injection point moves deeper. The balance-ported valve is configured such that no design casing pressure drops are required for closing. The pilot valve can be utilized later in the life of the well once the injection point is at the bottom valve and the well produces less than 150 BFPD. The pilot valve controls the injection rate into the well in self-intermitting cycles, allowing the well to feed in between these cycles. This allows for much lower gas injection rates and slightly increased production rates.

Traditional simulation-based approach for Gas-Lift Optimization depends heavily on the quality of reservoir and fluid data. Excessive OPEX and man-hours are needed to maintain data integrity and to ensure the models are suitably calibrated. Even then, pseudo-steady-state models do not consider losses due to multi-pointing condition and slugging behavior; and for dynamic multiphase flow simulation, the added complexity and man-hours required to assert accurate results cannot be sustained on a full field scale deployment. 

Gas-Lift Optimization essentially relies on the relationship between the Well Production Rate with the Gas-Lift Injection Rate. The objective of the proposed solution is to remove the need for well models, correlations and personnel from the optimization process and to implement a data-driven (model-free) approach that, by focusing just on the relationship of these variables over time is able to find the next best optimized Gas-Lift Injection Rate setpoint and to implement it directly at the wells via an automated local control loop.

This data-driven approach has been compartmentalized and developed as an Edge Application, ran directly on site in an IIOT gateway device. This method has the advantage of providing a predictive response that can be used directly in conjunction with a solver for single-well and multi-well optimization (handling well level and group level constraints by need). The application operates under iterative optimization cycles that progress towards system optimality. Even though well conditions are constantly changing over time, and consequently system optimality, these changes are reflected in the high-frequency data gathered by the application running on the gateway on site. Due to the iterative nature of the process, the solver can recognize these changes and react accordingly, adjusting based on the new system conditions in a closed-loop manner.

This paper presents the methodology and the results of a case study of eight wells, including both, single and multi-well optimization. All these wells are unconventional horizontal wells from the Permian basin in Texas, US. Regardless of the complexities associated with unconventional wells, noted by severe slugging and fast changing well conditions, in all the cases the results were outstanding. For the single well optimization, the candidate well was able to outperform the remaining wells in the pad by 5% in production improvement. For the multi-well optimization results vary from 5% to 25% production improvements. The full execution and optimization process was done in a fully autonomous manner, removing completely office and field personnel, as well as the need for well modeling from the optimization process.
This solution demonstrates a fully autonomous and Data-Driven Gas-Lift Optimization workflow, from data gathering and processing, edge computation, multi-well optimization based on field constraints, to the direct well implementation via closed-loop control.

In less than 9 years, High Pressure/Single Point Gas Lift has grown from 0 to about 3000 applications in unconventional wells and its use continues to expand with trailer mounted units to unload frac hits and applications later in the well life.

This paper presents examples of these expanding applications including case histories on unloading frac hits and shows how/why this very simple "new" technology grew from one person's idea to wide spread/ expanding adoption in a relatively short time.

Operating tips for increased effectiveness and potential applications in the future are also shared.

In many industries, technology improvements in high end devices eventually improves performance in lower cost like devices. The same is true in that gas lift equipment development for deepwater gas lift applications can help improve gas lift equipment designs used in land based gas lift wells. Today’s standards and client specifications for deepwater gas lift equipment requires extraordinary demands on equipment. The cost of intervention in deepwater installations due to an equipment failure is extremely high so the cost is justified. One would think that deepwater gas lift applications are a separate technology pool from standard land applications, but this is not necessarily the case. One example is that high injection pressure gas lift applications are becoming more popular in the U.S. Land Gas Lift Applications. Booster compressors are being used for higher gas lift injection pressures to produce higher fluid rates. The injection pressures and injection volumes applied are similar to deepwater offshore high pressure gas lift applications. Extensive testing to determine the actual pressure ratings and cycle life of a gas lift valve are also of paramount importance in deepwater applications. The testing and learnings of equipment required for deepwater high pressure gas lift applications can be of tremendous value to standard injection pressure operated gas lift equipment designs, materials selection, and supplier selection. This paper is the result of approximately 10 years of research and development for deepwater gas lift applications which has helped an equipment supplier improve equipment offerings for land based gas lift applications.

Gas lift is long known to be an effective and versatile form of artificial lift and is widely used in oil and gas production. Compressors are a vital part of the gas lift process and are present in large numbers in the oil and gas industry. The design of these compressors has for many years allowed for the release of hydrocarbons into the environment. Concerns over the environmental impact of these hydrocarbon emissions has increased scrutiny by the public eye and environmental regulators. In turn oil and gas operators are seeking ways to reduce hydrocarbon emissions to the environment from the compressors required for the gas lift process. A new and patented system has been developed to eliminate hydrocarbon emissions from compressors. This system is disclosed and an operator’s perspective is shared in how it is helping them to the environmental impact of their gas lift operations.

This paper presents a novel design of a gas lift check valve featuring an integrated pressure isolation mechanism, aimed at optimizing gas lift operations in oil wells. Operators utilizing High Pressure Gas Lift, or Single Point Gas Lift systems are often converting to conventional gas lift or other Artificial Lift methods once the production has declined. However, this conversion requires a workover and a large capital impact to the operator. This new integrated pressure isolation mechanism offers operators the ability to convert from HPGL to conventional gas lift without the need of intervention.

The proposed gas lift check valve incorporates a unique pressure isolation mechanism within its design to address these challenges. This mechanism allows for controlled pressure release, preventing issues such as valve slamming, gas migration, and excessive backflow. The integration of this isolation feature enhances the valve's reliability and extends its operational lifespan, contributing to improved overall system performance.
The paper discusses the theoretical foundation, design considerations, and simulation results validating the effectiveness of the proposed BurstGuard device. 

In conclusion, the integration of a pressure isolation mechanism within the gas lift check valve offers a promising solution to challenges encountered in converting gas lift systems, providing a more reliable and efficient method for optimizing oil well production. The innovative design presented herein has the potential to contribute significantly to the petroleum industry's efforts to enhance oil recovery processes while minimizing operational complexities and costs

Surface controlled gas lift has several obvious and predictable benefits, such as increased production due to deeper injection and continuous optimization. Installations over recent years have not only proven the validity of these benefits, but they have also offered some surprising and unanticipated advantages. 

Rather than focusing on the anticipated benefits of surface controlled gas lift, this presentation will only briefly mention them. Instead, it will focus on the additional advantages that were not even considered at the onset of the projects. As is often the case with innovation, these cannot be attributed to everything going right. Instead, they are benefits that have come to light due to anomalies, surprises, and problems.

Jet lift is often seen as a short-term solution or last case lift by many users. In this paper we will give an example of how jet lift is used as a long-term form of lift and highlight the benefits of using a downhole jet pump in horizontal wells with high decline rates. Please note that the term jet lift is used to describe the whole lift system while jet pump is used to describe the downhole pump. 

The data collected for this paper comes from two wells: one in the Permian Basin and another in the Powder River Basin. Production tests have been collected throughout the life of the wells to optimize jet pump performance and make any necessary adjustments. Using this production data, we have jet lift simulations to show horsepower requirements, pump intake pressure, injection pressure, and injection rate. All data shown for the Powder River well will be over a 5-year period and Permian well will be over a 2-year period. 

Powder River Basin well results: The jet lift system was installed in June 2017 and producing an average of 2,000 BPD. After 1-year and a jet pump optimization, the well was producing an average of 772 BPD. In October of 2018, the well was converted to rod lift and produced an average of 450 BPD. Over a 405-day period the rod pump had multiple downhole failures and workovers ranging from gas locking, rod load, and lower production than expected. In February 2020, 1-year and 3 months later, the well was converted back to jet lift and started producing an average of 350 BPD. A jet pump optimization test was performed in December 2020 and was producing an average of 510 BPD. The last production test on file for this well was August 2022 at 173 BPD. This well is still producing on jet lift for a total of 4.5 years, with only one workover during the jet lift operation due to a hole in tubing.

Permian Basin well results: The jet lift system was commissioned in April 2020, producing an average of 1,500 BPD. In September 2022, the system was producing an average of 390 BPD and was then increased to 462 BPD with jet pump optimization. The well is still producing. A corrosive and debris filled environment is the main reason the operator installed the jet lift system in this well originally and it has steadily produced for 3.5 years with no workovers needed.

Jet lift has a belief of being a short term or last form of lift when others cannot perform. This paper proves jet lift can perform well throughout the life of a well and meet production targets in challenging environments where other artificial lift forms struggle to keep uptime.

Plunger lift, gas lift, (GAPL)(PAGL), and sucker rod pumping are a few common forms of artificial lift that are heavily reliant on valves to maintain a seal in the system to extract fluids efficiently from the wellbore. 

This paper will outline the increase in well production performance when using a horizontal check valve on wells with Gas Liquid Ratios (GLR’s) conducive to plunger lift systems installed optimally in horizontal wells, also highlight design improvements when using these same valves in vertical situations.

Check valves are usually a key component of any bumper spring to allow fluid to enter the tubing string during a flowing cycle through the bumper spring itself, yet preventing fluid from escaping back into the reservoir while the plunger is descending to begin its next lifting cycle. 

HZCV (Horizontal check valves) or could also be referred to as horizontal standing valves are relatively new to the industry yet their functionality is similar to the traditional check valve or standing valve method which was typically a round ball creating a mechanical seal, or in other words, metal-to-metal contact between the valve and the associated seat. 

The I-Plunger is designed for Gas Wells and is an Instrumented Plunger that records pressure, temperature, depth, and plunger velocity. Information from the tool is collected and graphically presented for detailed analysis as well as a quick reference guide. Typical information that can be gathered from the I-Plunger is useful in determining plunger lift optimization, dual-stage plunger setup, frac and off-set production interference, pulse testing and horizontal well interference, gas lift and GAPL analysis, fluid levels, verify the plunger is traveling to bottom, bottom-hole pressure and temperature, multi-well pad operational interference, production effects from field compression and calculation of reservoir properties based on bottom-hole pressure when combined with other diagnostic tools. The I-Plunger program allows the Field User to initiate the I-Plunger on location in preparation for data collection and then this information can be used to optimize operational efficiency in the field, increase production, and for reservoir management. Data has been collected from a variety of Gas Lift Wells and is presented in graphical form for review. A detailed analysis for a gas lift well is presented at the end of this information showing evaluation and conversion to Gas Assisted Plunger Lift (GAPL).

Solids in rod pumped wells are a significant cause of failures and higher operating costs. Most solids cause continuing abrasion problems that are commonly misdiagnosed in typical failure analysis programs. This paper investigates the sources and nature of these solids, the impact on failures and technologies to reduce the adverse impacts of solids on equipment. These technologies will include a better understanding of existing products as well as emerging technologies. 

This paper will cover topics around the polished rod component of a downhole sucker rod pump. It outlines the development and testing of a Patent-Pending polished rod design by Q2 ALS, featuring a polished rod with a sucker rod end connection on the lower end. In contrast to traditional polished rod connections, the sucker rod connection has a superior threaded design, incorporating a shoulder for the coupling to make up against, resulting in a stronger pre-loaded threaded connection. This design not only creates a better connection at one of the highest loaded points in the pumping system, but also mitigates the risk of potential polished rod egress through the stuffing box upon failure. This innovative design minimizes the risk of failure at the connection point.

As operators draw down a well, massive quantities of gas are released into the wellbore which results in shut-downs and lost production. Using appropriate bottom hole assembly (BHA) best practices can help the operator pump through these gas slugs to maximize production and return on investment. Additionally, solid separation is an ongoing issue. Using a gas separator minimizes abrasion and corrosion related failures, keeping operating expenses lower.

The problem is twofold: Gas interference can lead to poor pump efficiency and severe sand issues can lead to sticking and excessive wear and tear on the pump. Both problems lead to unnecessary and costly operational expenses due to well failures and overall poor system efficiencies. 

Maintaining proper gas and solid separation widens operator options in regard to optimization and improved well control. This paper focuses on an all-in-one system that effectively allows operation through gas rates as high as 1900 MCF, as shown in case studies presented in this paper.

By maximizing separation area and minimizing downward fluid velocity, higher production rates are achieved in high gas-to-liquid ratio (GLR) environments. Installing this type of equipment reduces gas and sand interference, which in turn increases pump efficiency and extends the life of all downhole equipment. 

This paper presents the technology behind this combination gas and sand separation system and offers case study results that prove the positive impact of this tool on overall operating expenses.

This paper proposes an approach to diagnose pump-off condition versus gas interference condition utilizing a patented overlay of real time plunger velocity on top of the real time downhole card via pump-off controller interface. Field results showing the impact of this methodology are presented.

METHODS, PROCEDURES, PROCESS
Traditionally, the industry only looks at the surface and downhole card to optimize and achieve better well control. This requires a series of experts, dynograph interpretation and optimization processes. Even with all of this, scenarios exist where a downhole condition is not identified properly or leaves questions to be answered. 
One of the major problems in SRP wells is that the well will shut down when the pump fillage goes below a certain predetermined (user set) value, which can either be attributed to gas interference or pump off condition. If the first scenario applies, the operator may have the option to pump through this condition and achieve more production and drawdown on the well without damaging the system. If the second, the well should be stopped immediately to avoid equipment damage and failures.
Unfortunately, knowing the difference between these two conditions is not always intuitive or obvious. Moreover, pump-off controllers certainly cannot tell the difference. This causes the operator to lose potential production and revenue and leads to today’s condition where too many wells are carrying thousands of feet of fluid over the pump and are not achieving effective drawdown or hitting their production target.

RESULTS, OBSERVATIONS, CONCLUSIONS
Field results show that gas interference can be distinguished from pump off, reducing unnecessary shut down and improving drawdown in SRP wells.

NOVELTY
The options available today for plunger velocity are only available through modeling software and are not real time. This does not afford the operator effective control and live decision-making capabilities. The proposed offering puts the decision and control capabilities back in the operator’s hands.

The ability to have host software autonomously optimize control artificially lifted oil and gas wells has obvious upsides for operators looking for productivity gains both for their workforce and their assets. In recent years, many strides have been made to develop such algorithms to allow operators to maximize performance on their artificially lifted assets. One of the most significant challenges that remains is how to optimize dynamic wells. Although there are many rules-based approaches that optimize based on certain conditions, it is important to recognize how dynamic many artificial lift wells are, especially unconventional wells. Fortunately, as our understanding of autonomous optimization and unconventional wells improves, algorithms and logic have been developed to allow the host software system to optimize wells based on the dynamic changes in the well bore. 
After running autonomous control logic in the Bakken with a sample size of 40+ wells it is demonstrated that the logic updating setpoints such as idle time, pump fillage, and minimum pump strokes can be effectively optimized even with the well’s operation dynamically changing. This is especially important in rod pump wells that are experiencing incomplete fillage due to gas interference as well as fluid pound. Although those conditions have similar characteristics, it is important to utilize different optimization techniques as a well fluctuates in and out of these conditions. Other dynamic conditions such as sudden increases in inflow and wearing equipment are also conditions that can be optimized for as the operations change. This improvement in autonomous control technology has yielded significant benefits such as production increases where there is opportunity for uplift as well as improvement in pump fillage and decreasing the number of incomplete pump strokes daily, which can help reduce failures. This logic can be applied to a vast number of wells with different operating conditions and still autonomously make intelligent changes that dynamically change and improve operations as needed.

Rod lift applications in deep unconventional wells have created a wide range of new challenges for all components of the RL system. In the case of the sucker rod, the increased compressive loads, especially in the deeper tapers, combined with the deviation of the wells result in very high contact forces between rod and tubing as well as effective stresses on the rods that range from very high to negative values.  This scenario poses extreme challenges to operators who must choose between meeting their production goals in detriment of their system reliability or sacrifice production to avoid having holes in the tubing or deep rod failures.

This paper seeks to briefly describe buckling behavior in sucker rods, provide some best practices for sinker section design, and review the various sinker strategies available and their pros and cons. Euler’s equation is used to describe buckling behavior and show the variables involved in sucker rod buckling and a variety of data and specifications will be shared on sinker design and strategies. A short review of industry trends and the next steps will also be discussed. 

The analysis reveals that there are several ways to reduce or eliminate buckling in a system by using various sinker design strategies with varying benefits and drawbacks and that further research and development would be beneficial to identify improvements on sinker section design.

Pumping chemicals on wells with high fluid levels has always been a struggle on its efficiency as well as to reach the bottom of the well. This paper will go over the details of the downhole chemical technology to deliver chemical chemicals by microencapulating the chemical components into a chemical screen that is placed at the bottom of the tubing. This technology was installed in Gaines County after repeated failures on tubing due to severe scale and made a drastic improvement on the run time and production; decreased the failure rate down to nil