Sucker rods are simple in form and function, however, they operate in a sophisticated engineered system over great lengths without direct visibility. Because of this, we as engineers must do our best in predictive efforts to provide the best configuration for the highly dynamic system.

Rod string design software utilizes complex math to compute stress loading throughout the system. Design software w/ deviation included incorporates well-bore geometry to estimate ancillary loads throughout the design, i.e.: side-load & drag load from rod-on-tubing contact.

An improved method of accurately evaluating system and rod string stresses has been developed and computed. This method combines the industry standard Gibbs wave equation and trusted rod-string loading computation, taking it a bit further, evaluating the deflection behavior of the sucker rods throughout the deviated wellbores, and computing additional stresses based on arc deflection.

In instances of deviation and molded rod guides, sucker rod behavior changes dramatically. Dog-leg severity combined with most molded rod guides creates intermittent sucker rod rigidity and assumed perfect alignment with the tubing. This then causes the ability of increased bending moments and bending stresses. Fiber loading1 around the circumference of the sucker rod is then increased, leading to regions of the rod body exterior being subjected to stresses far higher than intended.

By accurately computing bending stresses and adding them to the total system loading through the deviated well bore, accuracy in the predictive system is increased, creating additional awareness to the system on a detailed, per rod level.

Despite general assumptions, stress loading is not linear throughout each sucker rod taper. This is often understood but not quantified, visualized, or addressed in string design software outputs. The effort of this paper is to provide detailed engineering awareness to rod loading, openly discussing with operators the effects of minor rod deflection and its associated stresses, and how this then encourages pre-mature fatigue fractures.

dv8 Energy and Black Mamba Rod Lift have worked together to build a web-based rod string loading fact checking system which validates and visualizes string design loading throughout the pumping cycle, addressing the bending stresses created from deviation and rod deflection in three different states: slick rod, guided rod, and under a buckling state. 

Rod pump failures often times exceed the failures rates of other downhole products, such as sucker rods and tubing. The largest section of the rod pump, and most costly to replace, is the pump barrel. Barrels of all different shapes and sizes, material grades and coating options are available to the market. The available coatings have been questioned for their durability while also being limited in their applications. Chrome barrels and NiCarb surface coatings are widely available but often times cannot be used in Acid Jobs (Chrome) or in heavy abrasive environments (NiCarb). Operators often seek a barrel that can operate in Acid jobs while also providing the wear and abrasion resistance needed downhole. Exceed has pursued the task of utilizing the proven success of boron diffusion in production tubing and applying that technology to the rod pump barrels. The strict tolerances on the ID of rod pump barrels have made this an extremely difficult task leading to many companies attempting this process, only to fail. Exceed will be presenting on the 2-years' worth of field trials downhole with US Operators on these barrels, primarily in the Permian field. 

Rod pumps often fail due to gas and solid interference. When the system’s check valves are unable to displace these solids or gas it can cause failure and significant damage to the overall rod pump system, such as intense ball rattling, plugged cages, inefficient pump fillage, and fluid pounding. 

Historically, the industry has dealt with these issues by utilizing stellite lined and insert guided cages with alterations for the ball’s clearance. However, these offerings have only provided a linear fluid path through the restricted valve areas. By changing this fluid flow path profile, check valves can improve the valve flow coefficient and more efficiently contains gas and solids in the fluid flow path. Additionally, by optimizing the flow design and creating a shorter ball travel length, Harbison-Fischer’s HFX cage reduces gas and solid interference by lowering the pressure drop during valve actuation, improving the overall run-time and pumping efficiency. 

A rod pump’s performance depends on its ability to open and close valves during production operations regardless of the well’s conditions. The HFX cage delivers a higher lifting force that maximizes pump fillage and overall performance.

This white paper aims to define the variables and understand the factors affecting the coefficient of volume (Cv) of a check valve (cage) used in rod lift applications. This understanding will help to predict the pressure losses in different pumping well conditions and help optimize the system’s valve efficiencies. Four variables will be discussed in this paper to identify an improved rod pump cage design: 1) fluid force on a ball type check valve 2) net lifting force and coefficient of lift on ball 3) fluid tracing and untracing on a ball surface 4) changes in ball resistance through the cross-sectional area. These four variables will be explained with either a general engineering equation, a finite element analysis, or a laboratory model with defined test parameters. The finite element analysis is used when general engineering formulas are unable to meet the fluid flow conditions. Similarly, the finite element analysis has few limitations to replicate actual well conditions for this study. It is critical to understand these general engineering and test analyses to understand a check valve’s efficiency & loss. 

In 2015 a proprietary quenched and tempered sucker rod product line was introduced to the North American market. Field results showed a considerable improvement of reliability and performance of the two proprietary rod grades (Critical Service, CS, and High Strength, HS versions) versus previously installed rod grades. The performance and reliability of over 300 installs are tracked and used to provide input to R&D and Product Development teams to continuously improve the products with the goal of further increasing run life and performance.

In 2020, Root Cause Analysis and ultimately, Finite Element Analysis (FEA) from rod failures in Chord Energy’s wells identified specific scenarios present in deviated, high load wells in the Bakken that created loadings exceeding the simulations from industry rod lifting and string design software by a significant percentage. This was key input to understand the necessary steps to further improve the corrosion fatigue performance of the rod grades.

An extensive research and development project identified a possible continuous improvement in the form of optimized Surface Texture & Finishing (ST&F). A matrix of various Surface Texture and Finishes were performed on samples with controlled variables for corrosion fatigue testing, which was executed at an in-house laboratory and benchmarked with earlier testing. Based on these results, the next generation product was deployed to wells in the Bakken for field trials, where previous rod grades had major challenges with run life.

Finally, field data and results on run life from these field trials will be included to showcase the performance.

The workover process provides a unique opportunity to directly measure wellbore friction as the rods effectively probe out the wellbore. Measuring this effect is challenging as no sensor exists that can provide an accurate, high resolution, high frequency measurement during the entire workover process. This presentation will analyze data gathered from a custom load & position sensor placed in-line with the rod-hook during the workover process. The normal rig crew process was unaltered beyond the initial installation and removal of the sensor. Detailed sensor measurements are available for each stroke of the rig and processed to determine the overall behavior of friction acting on different lengths of rod in the hole.

Inaccurate rod string spacing on rod pumped wells may result in significant maintenance costs and well productivity issues. To avoid unnecessary pump damage and optimize pump performance, precise placement of the rod string is key. This session will explore how a dual purpose well spacing tool /rod rotator addresses the need to adjust the rod string while harnessing benefits of a rod rotator. 

Rod pumping has been challenged by solids contained in produced fluids, as they reduce pump run-life. For horizontal wells solids risks have dramatically escalated, as hydraulic fracturing has exponentially increased in terms of number of stages and the amount of proppant pumped. EOR schemes can also escalate solids in produced fluids. To combat solids in the produced fluids reaching a pump, control methods have included solids separators and filtering screens. Both methods have realized limitations and therefore have not effectively resolved solids risks to acceptable levels.
Solids separators have typically been gravity and/or cyclonic based. Risk limitations with solids separators has been their ability to separate solids over broad solids particle size and flow rate ranges (a wide turn down ratio). Both cyclonic and gravity-based solids separators struggle to efficiently separate finer particles, such as 100 mesh frac sand, particularly when flow rates range from zero percent to 100 percent during a rod pump cycle. Cyclonic separators also face the reliability risk of erosion due to their inherent angular momentum solids separation design.
To effectively separate solids over a broad size and flow rate range, filtering is required. Risk limitations with solids filtering include filter screen plugging (from solids and scale) and from erosion. Eventually all filtering screens will plug off if flows are in the same or in one direction. For example, if flows are always in one direction, there is no place to contain the filtered solids other than on the filter screen itself. Running more filter screens for more filter screen surface area can extend the run life before plugging, but cost economics quickly come into play. Installing a filter screen bypass, for if in the event it becomes plugged, just exposes the pump to damaging solids once again. Solids can cause erosion, so filter screen designs need to minimize fluid velocities and use erosion resistant materials, which can escalate costs. Scale risks must also be controlled by designing for very low-pressure loss and drops through the filter screen and likely in combination with chemical treating – this means that filter screens placed upstream of a gas separator will likely be ineffective for preventing scale deposition due the expected high multiphase flow velocities.
A downhole self-cleaning filter system was developed to resolve these risk limitations. Proven surface facility self-cleaning filter screen system technology was re-designed to be deployed downhole.
The engineered system components were as follows:
• a filter screen engineered to hold and release solids down to 120 micron particle size; solids do not get retained in or on filter screen when fluid flow ceases during the pump’s downstroke,
• placement of the filter screen sequentially after the gas separation stage and inside the uppermost mud joint – in this location, solids laden liquid’s flow path U-turns from downwards to upwards through the filter screen and allows solids to be contained out of harms way into standard mud joints,
• continuous self-cleaning of the filter screen is achieved with a specially designed rod pump with a standing valve that back flushes the filter screen each pump stroke – a reverse pressure pulse wave and a back flush liquid volume each pump stroke dislodges solids from the filter screen and settles them downward into mud joints during the pump’s downstroke, and
• the filter screen is open-ended for allowing bypass in the event of filter plugging.
Field trials have recently been implemented with early time promising results for extending pump run life. The concept, design, field implementation and results will be shared.

Rod pumping horizontal wells is more complicated and challenging than for vertical wells. For system reliability reasons, it is common for horizontal wells to have a rod pump placed in the vertical section above the wellbore’s curve, which limits drawdown. This means the pump is placed a vertical distance above the producing zone and a pressure gradient of fluid between the pump and the producing zone exists. This pressure gradient can add 200- 500 psi of back pressure to the producing zone, limiting drawdown.
Drawdown is also limited by multiphase flows emanating from the horizontal wellbore that are inconsistent and sluggy. Flow regimes and inconsistent flow slugging tendencies are different in the horizontal, curve and vertical sections of the wellbore and these sections can compound each other for a bad unmanageable slugging condition at the pump’s location. Such inconsistent flows make efficient downhole pump gas separation very challenging. Consequently, a troublesome fluid level in annulus above the pump often remains. This fluid level can add an additional 200-500 psi of back pressure to the producing zone, further limiting drawdown.
To resolve these drawdown limitations and to therefore maximize drawdown, the pump would need to be lowered down into the curve section of a horizontal well. This presents several reliability risks, including:
• reduced run life with increased wear on the pump, rods and tubing,
• increased costs for surface pumping equipment and rod string due to increase loadings,
• reduced downhole gas separation efficiency at high wellbore inclinations, and
• reduce rod pump performance with valves not opening and closing efficiently at high inclinations.
Engineering a rod pumping system to operate at high inclinations reliably around the wellbore’s curve was undertaken. Field implemented has demonstrated a high success rate for dramatically increasing production and achieving good slugging conditions, while not realizing an increase in failure frequency. Results will be reviewed and shared.

To deal with gas and sand problems in their conversion and rod pump wells an operator company in south Texas started introducing a combined technology of two-stages filtration with a modified poor boy gas separator obtaining excellent results. This paper explains the technology used and shares the information used to design the tools and the results achieved in the first wells completed. The screening process to choose the best technology started by trying different technologies for gas and sand control below the rod pump. Different technologies were revised sharing data like sand particle size, pump design, fluid production expected, and wellbore configuration to get the best design from different companies. The technical and economic evaluation determined the combined system with two-stage filtration and gas separation was the best technology among all the installations. The results were spread to other wells changing the configuration based on the well conditions but maintaining the same principle of operation. After the installation of this technology in each well, it was clear a substantial increase in production among the wells that was caused for the improvement in the pump cards after the installation. The downhole equipment has been able to handle better gas production and no sand problems have been reported so far. The success of this technology has extended the operational capabilities of the pumps allowing the engineers to operate better their wells. Pump cards before and after the installations are summarized in the presentation to show evidence of the good results obtained. 

After the wells are converted from ESP to rod pump or when the gas represents an issue in the rod pumped wells, the production engineers are limited in the drawdown and the production they can get out of the wells. We are presenting an alternative for the operators to optimize the production's BHA and overcome sand and gas problems that limit the ability to increase the income of the oil fields. 

We present a survey of uses for distributed fiber optic sensors (DFOS) in oilfield production and operations. Downhole DFOS measurements of temperature, strain, and noise along the entire length of the wellbore serve as diagnostic tools for flow profiling and artificial lift monitoring. Field cases demonstrate DFOS abilities such as identifying gas lift injection points, quantifying stimulation volumes injected into multiple perforations, and providing actionable insights on paraffin challenges. Future applications of DFOS measurements for artificial lift diagnostics are proposed. 
 

The Permian Basin is well known for multiple remunerative producing zones. Recent development from the Delaware Basin has presented a need for economical chemical selections. Chemical treatment strategies applied in contemporaneous formations in the Midland Basin may not result in an optimized solids risk mitigation approach for the New Mexico Delaware Basin. Having the right treatment strategy in place is essential in preventing failures and downtime due to under deposit corrosion, microbiologically influenced corrosion (MIC), plugging and emulsion issues. Most operators have a firm understanding of localized problem facilities and well sets but have a less defined macroscopic perspective needed to minimize risk in terms of geography, geology and water chemistry.

This paper highlights a tailored chemical treatment strategy developed for solid mitigation for a Delaware Basin operator. Over 200 New Mexico and Texas State line Delaware Basin solid samples were collected over a two-year period, spanning 7 distinct producing intervals. Focus was placed on the most common producing zones such as the Wolfcamp, Bone Springs and Avalon formations. A statistical approach was taken to break down which formations have the greatest potential for paraffin, carbonate, acid soluble iron compounds and sulfate scales. 

Trends in the data suggested certain formations are more prone to certain types of solid precipitation. The data is in line with field observations across the Northern half of the Delaware Basin. Tying solid deposition history on a formational level helped the customer understand where treatment was no longer needed, where it was still required and where it may be needed in the future. 

The trends provide a proactive road map for risk mitigation and treatment optimization before a solid deposition event has occurred. An understanding of these trends have potential to save operators downtime and additional financial burdens associated with work over costs and deferred production in the Northern half of the Delaware Basin. A similar macroscopic approach in other basins may be applied to identify what proactive treatment strategies could be developed based upon the unique challenges of those regions and similarly improve field performance.

Gradual diminution of the flow path of hydrocarbon in the near-wellbore area is heavily linked to formation damage accumulation and well productivity reduction. Organic deposition in the formation and well bore area can result from the use of hydrochloric acid (HCl) during acidizing, especially in the presence of free iron, addition of organic liquids such as diesel, kerosene, or gasoline and the use of CO2 injection for EOR projects. Laboratory evaluation of the nature of the crude oil and stimulation fluids indicates the potential severity of the problem. 
The usage of organic and inorganic acids for inorganic deposits removal like calcium carbonate and iron sulfide has become one of the most used methods for well clean-up and stimulation. Unfortunately, due to the nature of the produced fluids, organic deposits like paraffin are coating the inorganic scale, minimizing the performance of the acid job. Typical aromatic solvents utilized to address the organic deposits are not highly effective, as they cannot be fully miscible in the volume of the acid, and they only dissolve a specific weight of paraffin based upon the molecular weight of the wax, temperature, and pressure before the solvent’s power is exhausted. 
A multipackage formulation has been developed, to be fully miscible in acid, maximizing the performance of the scale dissolution, by effectively de-oiling and penetrating the organic coating layer build-up on calcium carbonate and iron sulfide scales in shorter soaking periods. This novel formulation cleans spontaneously by diffusion, breaking and solubilizing the organic deposits and providing the following additional benefits:
• Water-wets the surfaces (formation, downhole equipment, tubing, and flowlines), including paraffin particles, preventing the re-agglomeration further down in the system
• Improves formation oil mobility by reducing the capillary pressure in the formation
• Prevents emulsion creation and acid sludge formation during acid jobs 
The work in this paper studies the effect of this novel chemistry when it is used in acid jobs, and presents case history information on testing, chemical application, and subsequent field results across the Permian Basin in conventional and unconventional production. 

This paper will cover multiple trials of a new combination of advanced gas and sand separation techniques which have now proven to consistently perform at an exceptional level which was previously unobtainable. Details of the performance will be thoroughly outlined. The assembly is designed to be very rugged, simple to run, and easily economical. 

In mature oil fields, the success of gel treatment results depends on the ability of the gel to reduce the high permeable formation without damaging to low permeable formation. Formation damage refers to the extent of damage reservoir rocks face from various drilling techniques and/or chemical treatment during well completion. A dynamic filtration test was used to investigate this effect using distinct core samples, brine concentrations and preformed particle gels. The effect of high pressures applied on the particle gels on various core samples with various permeability ranges was determined. These gels were pushed into the core holder with samples and the core permeability change was calculated. Different constant pressures were used to push the piston behind the gel samples. Then, the gel was flown around the core sample and collected in the outlet container. Various hardware was used to tighten the apparatus and provide connection between brine source, syringe pump, piston accumulator, core holder, and flow outlet container. The damage on the core was evaluated by comparing the original core permeability and the core permeability after gel treatments. Pressure gauges were used to measure the pressure drop across the core samples. The penetration of the particle gels into the low permeable formations can be decreased by the best selection of gel types, particle sizes, and brine concentrations under the reservoir condition. This work results can be used to select the best gel types for the right reservoir condition such as reservoir permeability, and reservoir pressure. 

Being able to calculate and predict the inflow performance from a well is critical in designing any form of artificial lift. The production/lift capability of whatever form of artificial lift chosen should closely match the current and future inflow performance of the well for the economics of the investment to be the highest.

Inflow performance estimation is also required to ensure that production is being optimized. When used with the outflow performance of the lift method, NODAL analysis can be performed to evaluate the entire production system for production enhancements.

This paper discusses the various methods available to determine the inflow performance of a well from the reservoir to the wellbore. The methods include the Productivity Index, Vogel Inflow Performance Relationship and Fetkovich method. In addition, methods to determine the inflow performance when the reservoir pressure is not known and predicting inflow performance over time are discussed.

One of the most expensive issues while workover operations are fishing and sometimes it ended up being a non-successful operation when the fish is left in the hole. The time expended trying to pull a fish in horizontal wells is particularly long and the costs are high. Proper planning and good practices should reduce the risk associated with this problem but as a contingency, a new tool has been incorporated in more than 150 installations in the Midland and Delaware basin during 2022. The tool was installed below the weakest point of the BHA or at the end of the tubing and its purpose is to catch the BHA at the TOL avoiding the fish to land in the curve or horizontal section of the wellbore. Once, the fish is maintained above the top of the liner and at the same time allows fluid flow around it, the fishing becomes an easier operation. Two case studies in the same field are presented where one well was installed with this new catcher and the fish was recovered in 3 days. On the other hand, the second well did not have a catcher and the company expended more than two months trying to pull the fish and in the end, they couldn’t recover it. This well had expenses of more than 1 million dollars without counting equipment expenses.

The percentage of oil wells using 3-Phase Electric motors controlled by Variable Frequency Drives is continuing to grow.  As new wells come online they are also added to existing Utility feeder lines.     As a result of increasing non-linear load density, utilities are gradually turning to stricter enforcement protocols.  New utility interconnect permits may be withheld until the utility is satisfied that a new pad will comply with IEEE519-2022.  Existing pads may trigger notices from a utility which can require compliance and outline punitive measures including disconnection if no action is taken.  This talk will explain why VFDs cause harmonics, how increasing the number of VFDs on a utility feeder impacts the power quality on the feeder line, and how to address harmonics for new and existing pads.  Passive filters, phase shifting techniques, active filters, active-front-end and matrix converters will be discussed and compared from a cost, performance and reliability perspective. Real world data from actual harmonics studies before and after mitigation will be presented.

Incomplete fillage conditions where the downhole pump does not completely fill up with incompressible liquid has been widely accepted to have detrimental effects on pumping efficiency and moreover the equipment longevity in sucker rod pumping applications.
Methods of synchronizing the pump displacement to the wells inflow and thus reducing incomplete fillage has been of keen interest to the industry. 

A sophisticated pump off control (POC) algorithm called Advanced Fillage Mode (AFM) & Fluid Level Model with a continuous feedback mechanism has been shown to significantly reduce incomplete fillage pumping cycles using a variable frequency drive (VFD) for speed control. 

Extended-reach horizontal well geometries and higher hydraulic fracturing stage counts have led to increased well productivities in tight oil plays across the Lower-48. However, lateral lengths in excess of 10,000 feet with complex fracture networks can also introduce more dynamic behavior and even more severe production declines over time, often exacerbated by tight oil formations that produce fluids with higher gas-to-oil ratios, sand and solids content, and water cuts. 
Accommodating these factors while cost-effectively managing rapidly changing production rates and depleting natural reservoir pressures can be a major challenge for artificial lift, especially during the first few years. However, the combination of gas lift and plunger lift technologies provides a flexible lift solution capable of not only optimizing production at every phase of the well lifecycle, but also adapting relatively easily and quickly as wells transition from the early-, to mid-, to late-life stages. 
The paper examines how leveraging gas lift, plunger-assisted gas lift (PAGL)/gas-assisted plunger lift (GAPL),and plunger lift at different points in the decline curve allows operators to take full advantage of the relative strengths of each method, including:
• Gas lift’s ability to mimic natural reservoir flow and efficiently handle varied production rates and well characteristics, including high GORs and solids. 
• PAGL’s ability to increase reservoir drawdown, stabilize production, and reduce surging as production diminishes to where gas lift becomes inefficient. 
• Plunger lift’s ability to carry accumulated fluids to surface at rates as low as a few bbl/d without an external power/energy source. The plunger also sweeps tubing of paraffin, scale, asphaltene, etc.
• GAPL’s ability to deliquefy loaded wells and produce liquids and gas from mature wells with little to effectively no natural reservoir drive.
This full lifecycle approach to managing tight oil well production encompasses three interrelated forms of artificial lift applied at distinct phases to collectively span the entire slope of the decline curve -- from IP to depletion:
• Gas lift in early life (maximum flow rates)
• PAGL through the mid-life plateau (moderate flow rates)
• Plunger lift and potentially GAPL in late life (minimum flow rates)
The paper provides engineering recommendations and operational practices to simplify transitioning wells from gas lift, to PAGL to plunger lift in response to changing production profiles as wells mature. It also details considerations for selecting surface equipment, downhole equipment, and automated digital controls capable of optimizing well production during gas lift, PAGL, and plunger lift/GAPL, without having to interrupt production or make capital investments to pull tubing or swap out components. 
Case history data from wells in the Mid-Continent and Permian Basin are presented to illustrate the benefits of adopting an integrated gas lift -PAGL-plunger lift approach to artificial lift and production management over the full well lifecycle. 
The purposeful application of gas lift, PAGL/GAPL, and plunger lift component technologies gives operators a single artificial lift equipment design capable of maximizing well performance at every point along the tight oil well decline curve. Ultimately, this translates into improved long-term production economics and the recovery of more reserves in less time.

With the use of mechanical long stroke units having stroke lengths of 291–416 inches, converting to rod lift is being done sooner. Rates of 400-900 bfpd are being achieved in wells as deep as 10000 feet TVD. This helps to eliminate running multiple ESPs to draw down a well into the 400-500 bfpd range. This presentation will discuss the history and demand of long stroke pumping units in the market today, challenges operators are facing using other forms of artificial lift in this specific volume range, as well as discuss case studies and real results about the mentioned wells. This will also cover the technologies being utilized such as pumping unit selection, BHA configurations, pump configurations, rod designs, and optimization with VSD Zone Control. 
 

This paper introduces a technology for handling solids above the discharge of the ESP pump that increases the run time of the well and prevents premature failure due to plugging or damage to the pump parts thus contributing to the reduction of carbon emissions and environmental impact. Additionally, the new technology was engineered to allow fluid injection through the tubing and its components can be dissembled after pulling it, providing the production engineers with valuable information about the downhole conditions.

The new device used to control the sand above the discharge of the pump was designed with the fundamental purpose of controlling the sand, allowing injection from the surface through the tubing and allowing the inspection and repair of its components after pulling it out of the well. The sand regulation system allows flow rates up to 15,000 BPD and has handled sand volumes up to 23,000 mg/L. While the internal mechanism that allows the control of solids and the injection through the tool is designed to allow up to 8 BPM of direct injection while maintaining a surface pressure of less than 600 psi.

The operational and performance advantages of this device have allowed its successful installation in several wells in the Permian Basin. After the installation, the run times have maintained high values, thus reducing the interventions to the wells and the replacement of the pumping equipment, thus reducing the carbon footprint of each one of the wells where this technology has been run. Additionally, the sensor variables have remained stable, which contributes to a higher cumulative production compared to periods where the pump was off for long periods, or the wells were under maintenance because of sand production. On top of that, each equipment pulled has been inspected and re-used to maximize the investment increasing the NPV of the projects. 

This new technology is the only one with the ability to protect the ESP against solids during shutdown events, allow flushing operations, and being inspectable and repairable. The use of premium materials, along with a special assembly system make it a tool with a long useful life.

Artificial Lift systems are crucial in optimizing production for horizontal oil and gas wells. As these wells face rapid reservoir pressure decline, increased gas and solids production, high deviation in well geometry, and unstable flow regimes selecting an appropriate artificial lift method becomes paramount. By implementing the right artificial lift system, operators can counter these challenges, maintain consistent flow rates, and maximize hydrocarbon recovery, ensuring sustained and efficient production throughout the well’s operational life. 
Electric submersible progressive cavity pumps (ESPCP) combine the benefits of an electric submersible pump (ESP) and a progressive cavity pump (PCP). The main advantages of an ESPCP are:
• Eliminates mechanical wear of rods and tubing.
• Suitable for deviated and horizontal wells.
• Same benefits as PCPs for solids handling and producing viscous fluid.
• Production rates can vary with the use of a variable-speed drive.
However, the ESPCP system with a traditional PCP is commonly used in heavy oil applications. Large gas volumes present in light oil formations tend to swell the stator elastomer, leading to lower efficiency and system failure. Besides, a conventional PCP has a limited temperature capability of up to 185 degF and is very sensitive to aromatics.
This abstract is about a new high-efficiency and reliable system capable of overcoming the main challenges in Permian’s operations: gas lock ( because of high GVF), high power consumption with traditional artificial lift systems for low rate applications, solid productions, parted rods, hole in tubings, among others.
Combining a permanent magnet motor (PMM) and a composite PCP, results in a more efficient pumping system that:

• Lowers power consumption and CO2 emissions reduction
• Increases production by setting the pump deeper, adding more lifting capacity
• Eliminates up to 80 % of failures of wells (elimination of rod string failures)
• Improves equipment reliability due to the elimination of a gearbox (the most common type of failure for ESPCP) 
• Allows for ESPCP production in light oil applications (up to 45 API)

At the well or through the cloud from any location in the world an operator can troubleshoot and analyze the performance of any well. Fluid level and dynamometer test can be acquired and used to analyze challenging sucker rod lifted wells without requiring the operator to be present at the wellsite. The operator can automatically acquire precisely time stamped high frequency data using an acquisition schedule created/modified remotely to acquire data for an extended time period and/or acquire individual test on demand. This paper will present examples of using this data to: 1) analyze/monitor an unconventional horizontal sucker rod well as it flumps up casing approximately every 10 hour and as it flows up the tubing as the VSD changes speed to maintain pump fillage, 2) show conventional tubing anchors trap gas below the tubing anchor in horizontal unconventional wells that flumping up the casing, 3) determine bottom hole pressures versus time from a pressure buildup or fall-off test created using an acoustic liquid level instrument with acquisition controlled according to a predefined schedule, 4) perform Walker fluid level depression test to determine the annular gradient below the liquid level and determine the producing pump intake pressure, 5) Setup a timer to control run-time for a marginal electrically driven sucker rod pumped well using acoustically derived drawdown and build-up data.

In the past an operator using a portable system and laptop was required to be at the wellsite to perform tests. Now the operator can schedule unattended fluid level, dynamometer, pressure, and power acquisitions test. Using internet or cell phone access a well anywhere in the world to monitor in detail with high speed and high-resolution wireless sensor data. Schedule time, frequency and sampling speed to monitor a well for an extended time. Schedule can be changed and data can be remotely retrieved without requiring the operator to make a trip to the wellsite to retrieve and view the acquired well data.

Standing and Traveling valves can be considered as the heart of a rod pump. An unrestricted fluid flow through the standing and traveling valves improve the pump efficiency and pump life. An unrestrained fluid flow through the traveling valve helps the sucker rod string to fall freely, which reduces rod buckling and eliminates unnecessary load on the surface unit. And in the case of the standing valve, it reduces the velocity and pressure drop across the cage, which lessens the gas lock in a pump. Standing valves with the least unused volume provide the highest compression ratio, that is helpful in a gassy environment. Zero restriction flow through the cages provides a free flow for the wellbore fluids with solid particles and keeps the cages from blockage. 

The important factors that need to be considered while selecting standing and traveling valves are: 1) Compression ratio, 2) Pressure drop, 3) Ball rattle and 4) Zero restriction flow, which will be discussed in this paper. 
The research team at Ellis Manufacturing has studied these factors along with different patterns of flow and engineered the patented Ellis JMAX 1-Piece Insert Cages. This paper discusses how the carefully engineered JMAX cages address all four important factors to provide improved pump efficiency for pumping in both conventional and horizontal wellbores.  

We are excited about the opportunity to present an in-depth overview of Oura™ (Optimization using real-time automation), an intelligent downhole electric valve designed for artificial lift and enhanced oil recovery (EOR). Oura™ brings cutting-edge capabilities to the forefront of the industry. Oura is also proving invaluable in various EOR methods such as Water, Polymer, CO2 Floods, and Injections.

Key Features of Oura™:

1. Real-time Monitoring: Oura™ provides real-time pressure and temperature data f    or both tubing and annulus, ensuring precise control and monitoring.

2. Variable Dart Position: With a completely variable dart position (0-100%), customers can manipulate the orifice to any size, up to 3/8".

3. Low Power Requirements: Oura™ operates on very low power and can be run off a single solar panel, facilitating remote installations and contributing to a reduced carbon footprint.

4. Multi-drop Capability: The technology can multi-drop up to 30 valves on a single 1/4" TEC, extending its reach to depths of up to 26,250 ft.

Progress and Installation Reach:

Since its conception in 2019, Precise has continuously worked on enhancing Oura™. We have installed over 200 valves across Texas, New Mexico, and Canada, solidifying Oura™ reliability and effectiveness in diverse operational environments.

Presentation Highlights:

Our upcoming presentation will provide a comprehensive overview:

1. (Precise) - Oura™ - A brief explanation showing off the design and functionality of Oura™ and our surface system. 

2. (XTO) - XTO to speak to the challenges & successes with Oura™ and how Oura™ fits in with their future operations. 

3. Closing: A concluding segment summarizing the key takeaways and opening the floor for questions and discussions.