Modern controllers are required to estimate various parameters from field data to provide effective diagnostics and control of sucker rod pumping installations. In some cases, however, the data are not only corrupted by noise but also contain outliers that are in gross disagreement with the postulated model. If included, outliers can distort the fitting process so dramatically that the fitted parameters become arbitrary. 
In such circumstances, the deployment of robust estimation methods is essential. This paper discusses the application of one of such estimators to rod pump systems. The approach is capable of identifying the outliers even when they constitute up to 50% of data. The problem that motivated this research is the estimation of the plunger leakage from the travelling valve check. Several other aspects of the system that can benefit from this method are also considered. The results are demonstrated using real data from the field. 

Objectives/Scope: 
A new methodology for automatic iteration on viscous damping enhanced with state-of-the-art pump fillage, fluid load lines and valve openings and closing calculation is presented. Field results showing the impact of the methodology in diagnosing downhole conditions, improving inferred production, fluid level, pump intake and horsepower calculations are shown.

Methods, Procedures, Process: 
The new approach uses a wave equation model with iteration on viscous damping paired with a traveling valve and standing valve calculation. Pump fillage and fluid load lines are calculated, which enables calculation of mechanical friction. The iteration uses a bisection method-like algorithm, which speeds up the convergence and removes the algorithm’s dependence on horsepower convergence criteria and other fluid and well variables.

Results, Observations, Conclusions:
In sucker rod pumped wells, efficiency and control of the entire system is ruled by elasticity, viscous friction and mechanical friction. Elasticity comes from the elastic behavior of the rod string and the propagation of stress waves due to the cyclic pumping operation traveling up and down the rod string at the speed of sound. Mechanical friction results from the rod string, couplings or pump coming in contact with the tubing. Viscous friction originated from produced fluid imparting a viscous force on the outer diameter of the rod string during operation. Those three factors are the basis for the calculation of downhole data from surface data to enable optimization and better control of sucker rod pump applications. Neglecting viscous friction leads to erroneous downhole data.
Very often, downhole cards have an over loop appearance which is physically impossible when considering pumping unit dynamics. This is due to the viscous force not being adjusted properly. Also, what can be mistaken from mechanical friction can be in fact completely removed from downhole data using appropriate viscous adjustment. Finally, operators traditionally overestimate their inferred production from the extra fictive load that is present on a poorly viscous friction adjusted card. The field data results presented in this paper show this new approach eradicates all these issues to deliver accurate and truthful downhole data.

Novelty:
The new approach iterates on the optimal damping factor for both the upstroke and downstroke for every stroke. Currently, most controllers utilize a manually adjusted damping factor, which leads to the damping factor not being adjusted for every stroke. Repercussions of this include overestimation of inferred production, overlooping phenomenon and appearance of excessive mechanical friction. 

Sucker rods are an essential component for rod pumping or rod lifting of oil and gas wells, but they have been limited by the use of metals and thermoset based non-metal composites (i.e., existing fiberglass sucker rods). Steel (metal) sucker rods have been limited by a low corrosion resistance, a low strength to weight ratio (i.e., too heavy), a low fatigue endurance limit and a relatively poor environmental, social and governance (ESG) rating during its lifecycle. Composite thermoset glass fiber (fiberglass) sucker rods have been limited by a low tensile modulus of elasticity (i.e., too stretchy relative to steel), a high cost (i.e., higher cost relative to steel), and a low toughness (i.e., low tolerance to compressional loads or high impact forces). Metal end fittings have also been a costly challenge for thermoset composite rods. Composite thermoset sucker rods using carbon fibers have offered a tensile modulus of elasticity comparable to steel but have been limited primarily by a very high relative cost to steel sucker rods.
Rod lifting has been further challenged by unconventional reservoirs and associated well designs comprised of vertically deep and long horizontal wellbores, where production is commonly comprised of high gas to liquid ratios and high initial liquid rates but with associated high decline rates. Electrical submersible pumps and gas lifting artificial lifting system are commonly used during the initial high production rate phase but eventually the well is transitioned to lower operating expense (OPEX) sucker rod pumping. Being able to transition to rod pumping as early as possible and at the highest production rate possible often provides the most attractive well economics. Unfortunately, high rate deep rod pumping has been challenged by excessive failure frequencies, mostly related to sucker rod failures. It is apparent that a cost effective and high reliability solution for deep high rate rod pumping is needed.
An ideal sucker rod for resolving its current limitations and application challenges has been defined and characterized as follows:
1. High strength to weight ratio,
2. High tensile modulus,
3. High toughness and fatigue/endurance limit,
4. High corrosion tolerance,
5. Cost comparable to low carbon steel alloys (i.e., KD rod), and
6. High ESG sustainability rating being recyclable and manufactured with a relatively low carbon footprint.
A composite material was identified, and it was hypothesized that it had the potential to satisfy development of an ideal sucker rod. Unidirectional fiber reinforced thermoplastic (FRTP) composite materials have gained significant attention in recent years due to their high strength/toughness, lightweight, excellent corrosion resistance, being partially recyclable with a relatively good lifecycle ESG rating and having comparable costs to steel sucker rods. This paper focuses on the development of fiber reinforced thermoplastic (FRTP) sucker rods, highlighting their potential advantages and challenges, for rod pumping (in general) and for offering an earlier transition from ESP pumping or gas lifting to reliable deep high rate rod pumping. 
The development of fiber reinforced thermoplastic (FRTP) sucker rods involves the integration of unidirectional high-performance fibers, such as carbon or glass, into a semi-ductile thermoplastic matrix. This is vastly different from thermoset composites, which use a hard and relatively brittle epoxy matrix around the fibers. A major and unique feature of an FRTP composite rod is its remarkably high shear failure resistance as compared to a thermoset composite rod. A high shear failure resistance means the rods have compressional loading tolerance and that an entire sucker rod string could be comprised of FRTP sucker rods. The design process, prototyping/testing and recent well trials/results show promise for FRTP sucker rods. This paper explores the development of fiber-reinforced thermoplastic sucker rods as a promising alternative for overcoming the limitations of steel sucker rods and thermoset fiberglass sucker rods. Field trials will be shared and reviewed.

Sucker rod pumping commonly requires the tubing string to be secured to the casing downhole near the pump to prevent tubing movement. Tubing movement can undesirably reduce downhole pump efficiency and/or damage the tubing and casing. Downhole tubing anchors are used for this purpose, but they can bring about risks that can increase operating expense and limit production.
For example, production can be limited if the annular flowby cross sectional area of a tubing anchor is restricting. Placement of a tubing anchor immediately above or below a downhole separator can reduce the efficiency of a separator and therefore also limit production. Sluggy and inconsistent flows from a horizontal well can further compound production challenges if an annular flowby restrictive tubing anchor is used.
The ideal mechanical tubing anchor is comprised as follows:
1. a costly catcher feature is not required and therefore is not included,
2. not flow restricting with an annular flow-by cross sectional area more than 2-7/8” tubing EUE coupling,
3. has full drift internal diameter equivalent to 2-7/8” EUE tubing, allowing for placement away from the separator,
4. does not require rotation to set or unset, reducing operational risks, allowing placement at high inclinations and allowing use of capillary injection lines,
5. allows for adequate tubing hanger tension setting weights, and
6. It is cost effective.
A new ideal tubing anchor has been engineered and developed to address production challenges and associated with horizontal wells, so production can be maximized. This new mechanical design uses eccentric flow paths and does not require rotation to set or unset. Case histories demonstrate this new tubing anchor successfully lowers operational risks and maximizes sucker rod pumping production.

The most common form of artificial lift is sucker-rod pumping. One of the main elements of rod lift system design is the selection of a downhole pump. This study examines the various factors that affect the selection and design of downhole rod pumps. This paper will examine the following five downhole pump components: barrel, plunger, cages, balls and seats, and seating assembly. Understanding the various well and system design factors that are examined when selecting each of these components is a crucial part in the design of the downhole pump. The dynamics that affect metallurgy, length, diameter, and pump configuration of the critical components are examined within this study. Once the aspects that affect material selection have been evaluated the different applications of API and specialty pumps are considered. By following the procedures and methodology outlined in this study, proper downhole pump selection can be implemented and the risk for premature pump failures is mitigated.

Effectively managing fluid production with high sand content poses a common challenge in various forms of artificial lift, whether it be addressing formation fines or handling proppant flowback from hydraulically fractured zones. This challenge is particularly pronounced in reciprocating rod lift applications, where the entry of sand and solids into the barrel/plunger interface emerges as a primary cause of pump failures. Conventional designs engineered to navigate fluid through tight space tolerances, experience issues such as plugging and accelerated abrasive wear of critical internal components like the barrel, plunger, and others.

A real-world illustration of this challenge is evident in the Aqua Dulce Field in Jim Wells County. An operator grappling with substantial sand production in mature Austin Chalk vertical wells faced a critical situation. The severity of sand and solids in one well-necessitated workover every 90 days on average, involving the replacement of the three-tube pump. These frequent workovers and pump failures significantly escalated the well's operating costs while contributing to a substantial loss in deferred production. This abstract explores the complexities and solutions associated with efficiently producing from wells characterized by high sand content, with a focus on reciprocating rod lift applications.

Nodal analysis is an approach for modeling a system of components to determine the impact of changes to any component in that system. It is a tool typically employed to ensure production is maximized in individual producing wells. However, this tool can also be used to analyze pipeline systems to study the impact of changes in deliverability.

This case study reviews the process used and the recommendations made from a nodal analysis that was performed to assess the impact on a gas gathering system from the infill drilling of 13 additional wells. From that analysis, an investment was made to upsize the gas gathering system to maximize the value from the existing and new wells feeding that pipeline. 

The nodal analysis approach began by developing an inflow and outflow performance model for the existing wells and gas gathering system. Once this model was validated, a prediction was developed to determine the inflow and outflow performance over time to include the new wells to be drilled. This performance over time prediction was then used to evaluate the economic benefits of making changes to the existing gas gathering system. This paper provides a review of the nodal analysis process taken and a lookback to compare the actual performance to the predicted performance.

Nowadays, concerns about global warming and the rise in greenhouse gasses grow each day. A major contributor to this is the hydrocarbon methane (CH₄) in natural gas. These concerns have caused government agencies, such as the United States Environmental Protection Agency, to require companies to reduce the amount of greenhouse gas emissions their oil wells release into the atmosphere. One such source of these gasses is small oil wells scattered across the United States. Eighty percent of US oil and natural gas production sites are low-production well sites. Low-production wells are a disproportionately large source of methane emissions, emitting 50% more than the total emissions from the Permian Basin, one of the world’s largest oil and gas-producing regions. It is estimated that low-production well sites represent roughly half of all oil and gas well site methane emissions. Many of the standard methods of natural gas management are either too inefficient or too large a scale for the amount of methane produced. This is why this group has created a compact flaring tower to burn off the emitted methane, producing CO2 and water. The expected outcome is to yield a product that will aid in the reduction of greenhouse gasses emitted by small stripper well facilities.

Methane emissions measurement technologies are evolving rapidly and becoming increasingly efficient over the last few years. The purpose of this paper is to introduce recent technological advancements that have helped operators in the US with more in-depth methane leak insights, improving the performance of emissions mitigation programs, ensuring proper management of associated risks, and delivering measurement-based methane emissions inventories. Technological advancements include both measurement hardware and emissions data processing algorithms and software tools. However, emission source detection, localization, and quantification are still areas of ongoing research and need further improvement. 

A recently developed novel model allows the detection, localization, and quantification of the total site emissions from oil and gas production facilities using continuous monitoring data. This model uses real-time and historical data to quantify emissions from various intermittent and continuous sources while differentiating any offsite emissions. A machine learning model is employed to build a unique model for each methane monitoring device to determine how the wind direction affects the concentration readings, simulating plumes from all potential emission sources and matching the plumes to the device model with a mixture model. This model is currently used to quantify emissions on hundreds of operating well pads across the United States. These models are complemented with operator notification and alerting systems to ensure timely actions by operators that result in reducing their environmental footprint and help keep the gas in pipelines. The most recent updates to the operator notification systems, called Smart Alerts, employ machine learning algorithms to eliminate unnecessary notifications to avoid alert fatigue. 

OBJECTIVES/SCOPE: 
Cleaning out a lateral is a powerful tool for restoring production in mature wells, but sometimes the hydraulics will not allow circulation with fresh water. An interesting technique for cleaning out such laterals has been field tested in the Delaware Basin, and it has potential application in many basins. As laterals age, a proper cleanout using this new method can restore production after a frac hit, prepare it for a refrac or for spotting acid across the lateral, run casing patches, clean out the top of a fish, and numerous other applications.

METHODS PROCEDURES, PROCESS: 
Cleaning out laterals with low bottomhole pressure (BHP) can be difficult when using water or brine because the hydraulics prevent adequate circulation. Often conventional techniques like nitrogen or diversion using rock salt or bio balls are required to clean out such wells, but these techniques are costly and can be unreliable. Microbubble / aphron based fluid systems can often work better than Newtonian or gelled fluid systems because: a) fluid weight can be lowered to 4.5 ppg, reducing the hydrostatic gradient, and b) rheology is improved to increase the carrying capacity of solids, reducing the risk of getting stuck.

RESULTS, OBSERVATIONS, CONCLUSIONS: 
Across our industry there are thousands of laterals that need to be cleaned out occasionally to maximize recovery. Due to length, debris volume, and BHP, traditional techniques such as venturis, nitrogen, rock salt, and bio balls are not always the best tool for the job. An 18-month trial was conducted by the Oxy Delaware Basin team. This trial consists of 23 lateral cleanouts using a microbubble/aphron based fluid system across both Texas and New Mexico. 

We have had a variety of results in performance response, including well enhancement, restored base production, no observed impact, poor candidate, negative performance, circulation not established, and microbubble / aphron based fluid system not needed for circulation.

We have learned that these jobs are not cookie cutter and need keen engineering for both candidate selection and execution. Based on our field experience, we have developed a process for candidate selection, job planning, and execution that can deliver a fully cleaned out lateral for maximized production. There is still more to learn, but we would like to share findings so that our industry can work together better maximize ROI across multiple basins.

Production engineers struggle every day with decisions on tubing size and flow path selection for their wells. This could be regarding what applications will be most appropriate over the life of the well, what timing would be appropriate for tubing install and/or flow path transition (annular to tubing flow), or what size would be appropriate for the remainder of the well’s life after a workover. Selecting the wrong tubing in naturally flowing or gas lift wells can result in heading, loading up, or unstable flow (if the tubing/flow area is too large), or excessive friction and loss of production (if the flow area is too small). Many papers have covered the task of artificial lift selection, however most provide a very large envelope for Gas Lift and few provide insight into tubing size and flow path selection. This paper aims to provide guidelines for tubing size and flow path selection based on nodal models matched to production data from a variety of operators in unconventional plays across the United States (Eagle Ford, Oklahoma Granite Wash, Permian/Delaware, and Dj Niobrara). We will compare sensitivities in SNAP nodal analysis software for a variety of liquid rates and gas to liquid ratios (GLRs), and briefly touch on hydraulic model selection for obtaining an appropriate production match when using nodal analysis.

Employing water injection is a widely utilized method to sustain continual oil recovery from reservoirs. This involves maintaining reservoir pressure, managing the oil rim, and facilitating the movement of oil from injection wells to production wells. Given that many water injection facilities still heavily depend on manual operation, automating the injection process emerges as a crucial strategy.

The technical discussion begins by exploring typical water injection techniques, followed by an analysis of challenges and suboptimal operations in water injection processes within the company and industry. The subsequent focus is on the design of a fully automated water injection system, encompassing considerations such as equipment availability and constraints in aligning with well injection requirements.

While an immediate transition to process automation for mature assets may encounter challenges such as system readiness, limited hardware availability, capital investment, and resistance to mindset change, a novel approach is proposed. This involves implementing guided operation and semi-automatic operation as initial steps, preparing the ground for a comprehensive automation rollout. Shifting from manual reliance to automation enhances the response time to process changes, thereby reducing near-miss and trip incidents and minimizing unplanned deferments in production.

Using simple salt water, (NaCl or K2CO3), and electrolysis, produces a more cost effective, environmentally benign biocide, HOCl (hypochlorous acid), and/or an environmentally benign alkaline ( KOH) , production enhancing, super water wetting, well treatment solution. The production enhancement from using small 1000–3000-gallon alkaline (KOH) Catholyte treatments on two new wells in the S.E. Oklahoma, in the Oil Creek formation (19-degree API oil} resulted in 200- 600% increases in oil production, with little or no associated water production compared to high water production in 23 previous wells in the same field. Similar treatments near Holdenville, OK and in Shackleford, County, TX have shown similar trends with reduced water ratios alongside significant oil production increases in each treatment. Also, small annular treatments using HOCl anolyte for wellbore mitigation and control of APB and SRB bacteria causing rod failures are shown to mitigate H2S and subsequent rod failures due to bacterial corrosion. Results illustrate one year plus remediation results, supporting treatment designs, and cost effectiveness. 

The Permian Basin began production in the 1920’s.  With that production of hydrocarbons has come the production of a lot of water.  In 2002 it was estimated that the production of water was 400 million gallons per day and that volume has increased steadily.  In addition, to water production, many reservoirs have reached an age where the paraffin and asphaltene content of the produced crude has increased.  Also, corrosive fluids production has increased, yielding deposits in tubulars.  Results of these three situations have made formation damage a significant problem in the Permian Basin and thus causing lower production rates in many wells.
This paper addresses the formation damages created by the events described above as well as those resulting from drilling, cementing and other well operations.  In addition, methods of dealing with the removal of these damage are presented.

The discovery of shale formations laden with hydrocarbons marked a significant turning point in the energy industry, especially because these formations exhibited minimal to no permeability. This inherent characteristic posed a substantial challenge for traditional extraction methods, leading to the advent of what is known as the unconventional play. The core of this approach is hydraulic fracturing, a revolutionary technique that not only generates high-conductivity fractures within the shale but also fosters the interconnection of these fracture networks, dramatically enhancing the extraction process. 

The advent of hydraulic fracturing has revolutionized the extraction of hydrocarbons from shale formations, characterized by minimal to no permeability. This paper discusses the mechanics of hydraulic fracturing, focusing on its role in creating high-conductivity fractures and interconnecting fracture networks to facilitate hydrocarbon flow. The study further explores technological advancements aimed at optimizing production plans, despite the inherent unpredictability of fracture outcomes. Emphasis is made on the impact of well spacing on fracture interaction. The overall extraction process is examined, highlighting the complex dynamics between well proximity and hydrocarbon recovery efficiency. 

Electrical Submersible Pumps (ESPs) are designed to apply a constant force to lift fluids in a well, with their flow rate being influenced by the pressure difference they generate. Optimal ESP design considers the formation's fluid yield, the fluid's density, and the required lift height, which together determine the pump's energy transfer needs. For high-productivity wells, the ESP's ability to increase pressure and consequently enhance flow capacity is crucial.

This research explores the impact of frac-hits, triggered by hydraulic fracturing in proximity to active wells, focusing on well performance metrics such as reservoir pressure changes, oil recovery, and the efficiency of Electrical Submersible Pumps (ESPs) in recovery. Through a comparative analysis of ESPs and Gas Lift systems in mitigating frac-hit repercussions, this paper aims to enhance strategic planning and risk mitigation in hydraulic fracturing operations.
 

The goal of a sucker rod is to convey the motion from the downhole pumping unit to lift fluid to the surface. When sucker rod lift is to be used on a well, it is necessary to choose the type of sucker rod that is optimal for the downhole conditions of the given well. Each sucker rod is designed to work in a specific environment, such as a corrosive or non-corrosive environment, and the loads encountered. The purpose of this paper is to report the findings on how to choose the optimal sucker rod for an application, based on a literature review.

The goal of a sucker rod is to convey the motion from the downhole pumping unit to lift fluid to the surface. When sucker rod lift is to be used on a well, it is necessary to choose the type of sucker rod that is optimal for the downhole conditions of the given well. Each sucker rod is designed to work in a specific environment, such as a corrosive or non-corrosive environment, and the loads encountered. The purpose of this paper is to report the findings on how to choose the optimal sucker rod for an application, based on a literature review.

With heightened technological advances in the area of late well life development and further production possibilities, there has been an increase in attention to plunger lift and the decision-making process that backs the selection of plungers in these plunger lift wells. It has been noted by companies, like ConocoPhillips, that ‘with more than 200 plunger lift systems in the San Juan basin, the plunger operator is the single most important factor in keeping a plunger lift system operating efficiently. If an operator knows certain principles of plunger operation and gas well mechanics, they can effectively maintain and troubleshoot the system… If an operator does not understand these principles, a system will lose efficiency due to poor maintenance… and they may be frustrated when the system does not work well.’ (Hingerl et al., 2020) This quote from literature reviews is an enlightening outlook on why the topic of how an operator chooses a plunger for PL wells is so important; Without knowing the principles of plunger operation or gas well mechanics both efficiency and production will be lost. Many variables go into the selection method of plungers. There are steps and methods that can aid in the classifying and understanding the lifecycle plunger lift wells to best optimize the wells. The first method is linked to understanding what kind of wells we have and what sort of plunger fits best; for example, a conventional or bypass plunger would be best equipped to handle a well that produces from pressure or gas volume rates. Continued surveillance of these wells and monitoring of the plungers used is crucial and even beneficial to a system consistently progressing in its life cycle. 

The phenomenon of liquid loading is a dominant limitation in developed gas fields globally. Apparently, all gas wells will experience this depleting process in the subsequent phases of their production. The primary problem in dealing with liquid loading is the issue of forecasting its occurrence and accurately determining its onset. This paper is focused on developing an improved model for accurately predicting liquid loading in vertical gas wells as the available models often show variations.
In this paper, an improved model for predicting liquid loading was developed on the hypothesis that the liquid droplet is disk-shaped and retains its configuration throughout the wellbore. The developed model was established on the fundamental principles of Turner’s model but offers better prediction than the former. The model was validated with Turner’s well data using the commercial Microsoft statistical tool Excel®. The actual critical velocities and critical flowrates of 106 wells from Turner’s data set were compared with the evaluated critical velocities and flowrates from the new model and the existing Turner’s and Li’s models. 

The error analysis carried out on the models showed that the models predicted the liquid loading status of the wells with average relative errors of 15.48%, 26.29% and 35.71%, with the improved model having the least error. The results obtained from this analysis indicate an improvement over the Turner’s and Li’s models. The improved model was applied to field data from Stubb Creek field in the Niger Delta to validate the efficiency of the model in detecting the liquid loading status of four (4) gas wells. The results obtained showed that the improved model detected the liquid loading status of the wells with the least percentage error of 10%. The analysis obtained using the data collected from Stubb Creek field revealed that the improved model gave a more accurate detection of liquid loading than the existing Turner’s and Li’s models. The improved model can be applied to gas wells with well head pressures lower than 500 psia and liquid/gas ratios within the ranges of (1-130 bbl/MMscf) to ensure the existence of a mist flow regime in the gas wells. The developed equations can also be applied in gas wells where annular flow regime and other flow geometries exist.   

It has been theoretically established that liquid loading is an issue bound to occur in all natural gas wells during their productive life. Therefore, the results of this study will be beneficial to the industry as it would enable the early detection and mitigation of liquid loading. The resultant effect of the early detection of liquid loading is its possible avoidance and increase in gas recovery rate.
 

To address the escalating demands for decarbonization within the petroleum industry, a pioneering technology known as in-situ hydrogen (H2) production via electromagnetic-assisted catalytic heating has recently been proposed for extracting clean H2 directly from petroleum reservoirs. This study explores H2 generation from hydrocarbon/water reactions in the presence of natural rock powders under electromagnetic irradiation. Real-time data on temperature profiles of rock samples, gas production, and concentrations of generated gases are monitored and recorded. Thermal Runaway (TR) phenomena are observed in both sandstone and shale rocks, occurring at 568°C for sandstone and 253°C for shale. Remarkably, upon TR occurrence, the post-TR sample can be efficiently reheated up to 600°C using significantly lower input power compared to fresh rocks. The findings also reveal that iron-based and other metal minerals in the sandstone rocks exhibit a noticeable natural catalytic effect in promoting CH4 conversion to H2, yielding over 70.0% H2 concentration as temperature approaches 650°C. In terms of oil conversion to hydrogen, a concentration of 60.7 mol.% H2 is achieved, accompanied by moderate percentages of CH4 and C2H4, along with a minor amount of CO. Additionally, water proves to enhance H2 generation via coke gasification within a temperature range of 330-580°C. Furthermore, throughout the experiments, negligible CO2 and minor CO emissions are observed, underscoring the potential for a carbon-zero H2 technology. The proposed technology holds promise in paving a new pathway for clean H2 production directly from oil and gas reservoirs.

During intermittent gas lift, a low-density fluid (gas) is used to lift a high-density fluid (oil) from the bottom of the well to the surface. As a result of the oil having a higher density than the gas, some amount of the oil falls back in the form of droplets or in a film along the wall of the tubing to join the next slug of oil. However, there is still no method to accurately estimate the fallback factor in the presence of several variables in the process.

In this paper, an attempt was made to develop an analytical model to predict the fallback factor of an intermittent gas lift cycle by continuing the mechanistic model from literature to include the change in length of liquid slug to estimate the fallback factor.

The contemporary rod pumping strategy for horizontal wells typically involves placing the pump at or above the Kickoff Point (KOP) to ensure the rod string and downhole pump operate in relatively low dogleg severity conditions. However, in certain types of reservoirs and well conditions, it may be beneficial to place the pump below the KOP. This paper presents a case study from Devon Energy’s Powder River Basin and Delaware Basin Assets, where over the past decade, more than 1200 pumps have been operated below the KOP in over 400 unique wells. The study examines the conditions, methodologies, and outcomes associated with this approach, highlighting its potential advantages, operational insights, and recommended best practices.

This paper discusses and provides a number of routines codified in practical spreadsheets that production engineers and operating personnel will be able to use to do calculations helpful for visualizing, analyzing and evaluating common production problems/scenarios.  Using these spreadsheets will save time and increase the user’s effectiveness in handling various production challenges and Artificial Lift situations.   Spreadsheets that will be included are as follow:
•    Gas lift Performance for Oil Wells
•    IPRs for Oil Wells: PI/Vogel & Back Pressure
•    SRP Pump Efficiency with Gas Separator Performance
•    Rod Loading: New and Old Goodman
•    Gas Well Multiphase Flow Gradients and Critical Flow Calculated
•    Gas Assist Plunger Design
•    Visualize Pump Dynamometers: Gas and PIP
•    Down Hole SRP Pump Clearance
•    Oil Well Tubing Performance: Inject at any Point in Tubing
•    SRP Pump Spacing
•    Calculate Gas Z Factor
•    Analyze Gas lift P & T Surveys
•    Plunger with Time with Declining IPRs
•    Present Value Profit ()of Staged AL with Declining Production
•    Limitations for Drawdown for Pumps
•    ESP Gas Separator Performance: Drawdown Possible 
•    Gas Well gas lift Performance
•    And others

This paper explores the application of boron-carbide (B4C) treated rod pump parts in sucker rod pump (SRP) wells, as a solution to the challenges posed by modern-day drilling and completions practices. These practices often result in sandy, corrosive, and highly deviated wellbores, leading to increased wear, frequent interventions, and downtime in rod lift systems. The paper highlights the improved run times a large producer in the Permian Basin was able to achieve by utilizing boron-carbide treated components in their sucker rod pumped wells. The evaluation aimed to assess the run time performance of a sample of 30 wells, focusing on wells with prior run-time and failure mode history established. The results showed improved run times in many of the wells evaluated and highlights the components and configurations used. The paper further discusses the B4C treatment technology the potential in enhancing the performance and longevity of various artificial lift equipment.

As an operator, success rests in trying to maximize safety and production while minimizing your cost and downtime. Most operators choose ESP as a first form of lift and will later transition to gas lift, rod pumps, jet lift, etc. Other operators choose to use gas lift or rod lift as a first form of lift.

Each of these forms of lift presents its own rewards and drawbacks. 
For example, overtime, ESP can become oversized for the production requirement of the well. At that point, it can become more economical to install gas lift, rather than resize the ESP pump. Solids, Deviation and corrosive environments are inhibitors for ESPs and rod lift limiting the production potential for the operator.

In other applications, long stroke units or conventional rod pumping offer the best solution with high production rates at a much lower cost than an ESP installation.

In this paper, benefits and challenges for each ESP, Gas Lift and Rod Lift and insights on the best conversion time, will be discussed. 
This paper aims to provide data to help the customer understand how employing the best type of lift at the most appropriate time directly translates to maximizing revenue and production while minimizing losses and failures.