2024 Southwestern Petroleum Short Course Schedule

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.

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.

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.

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)

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.

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.

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.

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. 

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.

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: 
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. 

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.

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. 

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.

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.

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.

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.

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.
 

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.

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.

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. 
 

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.

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

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.

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).

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.

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.

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.

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. 

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.
 

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.  

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.

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.

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. 

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.

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.

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.

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.

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. 

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. 

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.

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 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.

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 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.

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.    

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.

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. 

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.

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

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.

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 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.

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. 

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 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. 

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. 

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.

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. 

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.

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.

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. 

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.

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. 

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.

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.

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.

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

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.

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.

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.

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.

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.    

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.  

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.

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.

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.

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.

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. 

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.

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. 
 

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)

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.

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.

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.

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.

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.

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.

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.

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.

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

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.

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).

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.

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.

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. 

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.

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. 

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.

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.

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.

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.