About the Event

The 2021 International Sucker Rod Pumping Workshop will be held from February 8th to February 12th, 2021. Continuing education classes will take place on February 8th-9th, followed by technical sessions on February 10th, 11th, and 12th. This year’s workshop will take place in a virtual environment, expanding opportunities to learn all about rod pump artificial lift to more people in more countries than ever before! We are excited to offer participants a cost effective, safe, modern online venue for education and networking opportunities from the comfort of your couch.

Event Flyer – English | Event Flyer – Spanish | Event Brochure | Exhibit/Sponsor

Dr. Victoria Pons is the General Chair for the 2021 Sucker Rod Pumping Workshop.

Students are eligible for discounts on classes and sessions. Please contact us to receive a code to use for special student pricing.

Advanced registration ($50 discount) will close on January 22, 2021.

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Keynote Speakers
Gabor Takacs

Dr. Gabor Takacs

February 10th | 10:30am
Back to Basics: Gearbox, Torques, and Counterbalancing
Why doesn't the petroleum industry counterbalance the pumping units to minimize power usage and maximize efficiency?

Gabor Takacs is a professor emeritus at the Petroleum Engineering Department at the University of Miskolc, Hungary since 2017. He held the position of Department Head from 1995 till 2012. He holds MS and PhD degrees in Petroleum Engineering and a doctorate from the Hungarian Academy of Sciences. Between 2007 and 2010 he was acting Director of the Petroleum Engineering program at The Petroleum Institute (now Khalifa University) in Abu Dhabi, UAE; earlier he taught at Texas Tech University, USA in 1988/89. He has more than 35 years of teaching and consulting experience in the production engineering field. He is the author of several books on artificial lift technology; “Modern Sucker-Rod Pumping” (1993), “Sucker-Rod Pumping Manual” (2002), “Gas Lift Manual” (2005), all published by PennWell Books, USA. His books “Electrical Submersible Pumps Manual” (2009), “Sucker-Rod Pumping Handbook” (2015) and “Electrical Submersible Pumps Manual” Second Ed. (2017) were published by Elsevier, USA. Dr. Takacs has more than 100 technical papers to his credit. He has taught more than seventy 5-day courses on artificial lift topics (gas lifting, ESP, SRP, etc.) for many oil companies in Libya, Mexico, Argentina, Indonesia, UAE, Romania, Malaysia, Peru, Oman, India, Egypt, Qatar, Kuwait, Vietnam, and Austria; and is an internationally known consultant and instructor on production engineering and artificial lift topics. Dr Takacs was instrumental in setting up the Hungarian Section of SPE in 1992 and was the section’s first Chairman between 1992 and 1994. In 1995/96 he was selected SPE Distinguished Lecturer, was Outstanding Technical Editor for the SPE journal “Production and Facilities” 1992-2003; chaired the Artificial Lift TIG (Technical Interest Group) of SPE in 1997-2003. Dr Takacs received the “Regional Production and Operations Award” from SPE in 2017.

Patrick Bangert

Patrick D. Bangert

February 11th | 10:30am​
Artificial Intelligence and Machine Learning in the Digital Oilfield
How to use AI & ML to troubleshoot and optimize the operation of sucker rod lifted systems.

At Samsung SDSA, I direct the AI Engineering and AI Sciences teams. The AI engineering team develops the Brightics AI Accelerator that provides distributed training and automated machine learning to speed up the creation of an AI model. The AI sciences team makes models and provides expert consulting services. Together we supply the full spectrum of AI model development backed by state-of-the-art technology and human expertise.
With a background in the process industry (chemical, power, oil and gas), I have an eye on practical applications that deliver value in the real world. Integration of domain expertise matters, and so does the change management whenever a new AI technology is to be adopted. From optimizing power plant efficiency, to enabling predictive maintenance in upstream and downstream plants, I have worked on practical AI projects on four continents.

Siham Al-Habsi & Nawar AL Abadi

February 12th | 10:30am​
Diversity & Inclusion
Implementing best practices to provide equal opportunities in the oil and gas industry.

Siham Al Habsi – Born in 1989, graduated as BSc. Chemical Engineering from Caledonian College of Engineering in 2013.

Nawar Al Abadi – Born in 1992, graduated as BSc. in Mechatronic Engineering from Asia Pacific University, Malaysia in 2014.

Siham and Nawar proudly joined Petroleum Development Oman Company in 2014 as graduate trainees in Production Operations, which required field site exposure to PDOs interior sites.

Nawar and Siham have taken up the challenge of working within a male dominated environment as well as adapting and dealing with harsh environments. Nawar became a Field Programmer in 2017 as well as one of the first Omani woman to be established in the field within PDO as a production supervisor in 2019.

After completing her graduate program, Siham had the passion to continue working on site, and became Field Programmer in 2017, as well as joined Nawar as one of first Omani Women to be established as Productions Supervisor in 2020.

As Production Supervisors, they led a team of male operators, dealing with production facilities, engaging with multiple contractors, ensuring safe, efficient and effective operations and analyzing production’s efficiencies.
Nawar is proud to be given the opportunity to achieve the mission for equal rights for women with passion, dedication and commitment. She has taken a unique journey setting an example and inspiring women to take on opportunities to work in the field side by side with male colleagues for the development of her country.

In 2019, Nawar was rewarded by OFA (Oman French Amitie) association as 2019 Inspirational Omani Woman and actively participated in increasing awareness of gender balance and diversity at workplace.

Siham and Nawar stand proud as women serving in the field in the oils and gas field operations and encourage their female peers and colleagues to take on similar aspirations and opportunities.

Continuing Education Classes

ALRDC is proud to offer the following classes as part of the 2021 International Sucker Rod Pumping Workshop. Each day features three half day classes, split into 3 sessions designed to be taken consecutively over the two day period. Paid registrants may move freely between any of the classes at any time.

Registration is $150 USD for both days.
Students and laid-off or furloughed members are eligible for discounts on classes. Please contact us to receive a code to use for special pricing. 

February 8 | 8:00am - 2:00pm CT

Session 1

Dynagraph Analysis Part One
Instructor: Louis Ray

History of Surface Dynamometer Card Generation | Surface Dynamometer Cards | History of the Calculated Downhole Card | Gibbs and Everitt-Jennings Downhole Card Methods |Effective and Buoyant Load DH Card Display | Downhole Card Shapes | Downhole Card Shape Class Exercise

Session 2

Recommended Practices for Rod Pumping
Instructors: O.L. Rowlan, J.F .Lea, S. Gault, G.Fernandez

There are a variety of recommended practices for producing sucker rod lifted wells to provide optimum operations and profits.  Recommended practice include properly installing equipment in the well, providing proper chemical treatments, preventing rod on tubing wear, identifying cause of well failures, and periodic surveillance of the well.  Dynamometer and fluid level surveys are used to identify when the well is properly operating and when there are operating problems.  The presentation reviews older practice and mentions newer practice to assist the operator with operational concerns.  In general, sucker-rod pumping is the premier method of artificial lift.  Many operators will only use some other lift method after justifying why not to use beam lift.  This presentation reviews many of the concerns that operators face when using the sucker rod pumping system. Operational concerns are introduced with a review of the advantages/disadvantages of the system.  Guidelines for sucker rod applications, downhole pump recommended practices, surface unit best practices, tubing, gas separation, use of fluid level detectors (fluid shots), effects of casing pressure, and finally some mention of corrosion solutions.  The paper reviews recommended practice to assist the operator with operational concerns.  

Session 3

Failure Cause Analysis
Instructor: Russell Stevens

This failure cause analysis training will provide information critical to solving repeat failures in problem wells and provide recommendations for immediate and/or future changes. Utilizing an extensive library of photographs and failure documentation, this 4 hour training course will help both engineering and production personnel identify failures and initiate effective corrective actions that positively impact operating expenses. The extensive training covers:

  • Understanding different failure modes (i.e., brittle, ductile, and fatigue);
  • Identifying failure causes (i.e., abrasion, corrosion, material, mechanical, workmanship, etc.);
  • Corrective actions to mitigate failure causes (i.e., reducing gas interference, pump off, etc.); and
  • Utilizing design tools to prevent failures (i.e., Gas Separator Simulator, QRod, Rodstar, SRod, TAM, etc.)

February 9 | 8:00am - 2:00 CT

Session 1

Dynagraph Analysis Part Two
Instructor: Louis Ray

History of Surface Dynamometer Card Generation | Surface Dynamometer Cards | History of the Calculated Downhole Card | Gibbs and Everitt-Jennings Downhole Card Methods |Effective and Buoyant Load DH Card Display | Downhole Card Shapes | Downhole Card Shape Class Exercise

Session 2

Troubleshooting Gas Interference, Impact Loads
Instructors: O.L. Rowlan, J.F .Lea, S. Gault, G.Fernandez

Probably the “top secret” is to produce wells with complete pump fillage. More efficient operations and lower failure rate will result if wells are operated with a pump filled with liquid. Data from 6000 Permian Basin wells will be used to show stroke length combined with strokes per minute are important; but the primary reason for a long run life is to always operate with a pump filled with liquid. Data will show that long and slow versus short and fast both result in high failure rates when the pump has incomplete pump fillage. Frequently inspection of dynamometer data collected on sucker rod lifted wells often shows incomplete pump fillage. The #1 recommended practice of operating a pump filled with liquid must not be known by the operator and therefore must be “secret”. Incomplete pump fillage, tagging on the downstroke, and other downhole conditions that contribute to rod buckling and subsequent accelerated rod/tubing wear and possible other damage. Commonly applied solutions such are weight bars and rod guides are reviewed. Dynamometer cards, particularly calculated downhole pump cards are used for diagnostics of problems that exist in a well. To maintain efficient operation requires that pumping should be done only when the pump is filled with liquid.

Session 3

Service Rig Care & Handling
Instructor: Mike Brock

Failure Analysis Teams and Failure Meetings
Instructor: Becky Ogden

Failure Analysis Teams and Failure Meetings
A well-managed failure analysis team and failure meeting is critical to the identification and prevention of downhole and surface equipment failures. This short-course will give an overview of best practices for the creation of a Failure Analysis Team. We will also present and discuss the outline for a failure meeting, including expectations of the chemical, downhole pump, and downhole equipment vendors.
It will discuss the advantages of creating a formal team composed of multi-disciplined vendors and suppliers, in addition to the Operating Company’s Engineers/Chemists, and will stress the importance of 2-way communication between all vendors and the Operator.
We will discuss the roles of each participant and the expectations of the team, as well as the importance of documenting the root-cause of each failure and noting any future steps associated with the “next pull” methodology to prevent future failures.

Service Rig Care and Handling
A well designed and operated sucker rod system will prematurely fail if the equipment is damaged when running into and/or out of the hole. A majority of service crews lack the training, techniques, and equipment for proper care and handling, but this also applies to supporting functions such as trucking, warehouse, forklift operators, and others.

This course will cover the API recommended practices for care and handling of tubing, downhole pumps, and sucker rods.  Field based best practices that improve adherence will be covered as well as issues that have often been witnessed and addressed.   

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Technical Sessions & Panels

ALRDC is proud to offer the following technical sessions and panels as part of the 2021 International Sucker Rod Pumping Workshop. 

Registration is $250 USD, covering admission to all three days of sessions.

Students and laid-off or furloughed members are eligible for discounts on sessions. Please contact us to receive a code to use for special pricing. 


8:30 – 9:00
Use Dynamometer Data to Identify Solids Impacting Pump Operation
Lynn Rowlan, Echometer

Dynamometer data can be used to identify sucker rod pumped wells producing liquid with solids impacting the operation of the sucker rod pump. Foreign material in the pump can cause erratic pump behavior due to the delay in traveling valve, TV, ball going on seat and can cause severe shock loads which result in increased rod string and pump failures. On the up or down stroke when solids hold the ball off the seat the concave-outward shape of the pump card can be used to diagnose excessive pump/plunger assembly leakage. The standing or traveling valve stuck open condition occurs when trash, sand, scale, asphaltene, or some other foreign material lodged in the valve assembly causes the ball to stick in the cage and/or rest off of the seat. When the ball is continually stuck off the seat during the stroke, then a constant load (0 or fluid load) is applied to the rods and pump action of transferring the fluid load between the rods and the tubing ceases. “Spikey” loads can also occur if solids are dragging between the plunger and the barrel. The current recommended practice for sucker rod pumping is to operate with the down hole pump filled with liquid, but the presence of solids in the pump can create dramatic changes the typical rectangular full pump card shape. Field dynamometer data acquired on many different wells will be used to show the symptoms of solids/foreign material impacting the performance of the sucker rod pump.

9:00 – 9:30
Hydraulic Pumping Unit Evaluation
Dimas Reyes, YPF

The last 10 years, the hydraulic pumping units are recognized as an alternative for wells with artificial lift systems using sucker rods pump, this technology gained more popularity compared to the previous decades, accompanied by some technological improvements in the control and with changes that simplify some operation practices and maintenance cost.
Although from the beginning Hydraulic Pumping Units were unpopular due to common leaks and high maintenance frequency, unpopularity that today remains in most cases. However, it has been observed how operators increased the use of this equipment, with the focus on applying in wells where the balance between benefits and differences with respect to known practices with traditional pumping units are justified.
Mainly for deeper and deviated wells, gas lock problems. As it is known, long strokes and operating at low velocities always are to favor the wells’ production stability and reduction of failure rate on the sucker rod pump systems. Of course, considering that we must rescue the significant differences in the initial investment compared with the mechanical pumping units with long-stroke and more than 30.000 pounds structural capacity, in addition to the operational versatility and less time it takes to make adjustments to velocity and stroke length to match the desired production rates, and much less time to install and put wells in production. Some improvements in the control systems that allow not only to change the SPM from a remote system, but also the stroke length and pump spacing, thus minimizing field personnel assistance and resources allocated for such purposes.
Additionally, while we acknowledge important benefits in the way we operate the artificial lift system, it must be considered that when selecting the candidate wells for a hydraulic pumping unit, we must add the energy efficiency indicator as in any system evaluation. In the last two decades, although it is a discussion that has been going on for several years, not much has been documented about it.

9:30 – 10:30

10:30 – 11:30
Keynote Speaker – Dr. Gabor Takacs

Back to Basics: Gearbox, Torques, and Counterbalancing
Why doesn’t the petroleum industry counterbalance the pumping units to minimize power usage and maximize efficiency?

11:30 – 12:00
Panel Discussion
Back to Basics: Gearbox, Torques, and Counterbalancing
Panelists: Leslie Malone, Dr. Gabor Takacs, Lynn Rowlan, Peter Westerkamp

12:30 – 1:00
Performance of Special Sucker Rod (AlphaRod® CS) After 5 Years of Field Experiences Worldwide
Esteban Oliva, Tenaris

After many years of satisfactory results gotten with conventional steels sucker rods, application has been restricted to neutral or benign environments. As this environment gets more aggressive, standard materials reach their limits. In this scenario, this new special sucker rod (AlphaRod® CS) was created to deliver superior performance on benign environments and at the same time overcome more demanding requirements offering a solution to fatigue and corrosion-fatigue problems, one of the major and unpredictable causes of premature failures in O&G industry. Since its development, more than five years of field trials and in excess of 200 installations worldwide are summarized in this paper in order to validate its performance at field conditions vs the improvement found on laboratory tests. With proven field performance evidence, deep failure analysis and worldwide data comparison allowed us to understand and detect patterns that defines with more precision the product application range in terms of corrosion content and/or stress levels. According to laboratory test results, the product has shown an outstanding performance giving 2 to 3 times more resistance than conventional sucker rod steels. In the same vein, field experiences showed an important improvement in terms of run time. In particular, unconventional reservoirs producer wells push the limits from a loading and harshness point of view on existing ALS in a fashion that creates problems with reliability. This new special sucker rod (AlphaRod® CS) improves sucker rod string reliability in those conditions and helps reduce downtime and OPEX to operators.

1:00 – 1:30
Successfully Pumping the Curve with Thermoplastic Liners
Anne Marie Weaver, LPS + Revolution Resources

As shale wells are intentionally drilled deviated or horizontal to reach deeper and varied formations, the resulting wellbore can contain curves in the well trajectory with inclinations greater than 90 degrees.
This phenomenon can make lifting fluids using rod pumps problematic due to the extreme deviation and forces the operator to compromise production for the safety of pumping the well from the vertical section above the curve.
In an effort to increase production and reduce gas and slug flow, operators have attempted to pump the curve with varying levels of success.
Thermoplastic liners, which are mechanically bonded to new or existing tubing, significantly increase run time by preventing rod/pump on tubing contact. Thermoplastic liners also remove the need for rod guides and protect the tubing from corrosive reservoir fluids, therefore improving corrosion related failures. Finally, thermoplastic reduce friction forces by half compared to bare steel and by two thirds compared to rod guides, thus decreasing operational expenses.
In this presentation, results from a case study where thermoplastic liner was installed on five high failure rate wells show that pumping the curve is a economic and feasible option for operator.

1:30 – 2:00
Rod Pump Workovers – Improving Efficiencies
Rick Webb & Mike Hendrix, DNOW

Nonproductive time and delivery charges account for a large portion of the cost of a rod pump workover.  The purpose of this paper is to explain an improved process for supplying all replacement components on a rod pump workover.  This process is currently being implemented by three major operators in North Dakota.  The components will all be brought to location on a “workover trailer”.  The trailers are pre stocked with a predetermined Bill of Materials agreed upon by operator and supply company and will include any item that may need to be replaced during the well pull.  At the end of the pull, the operator is only invoiced for the material taken off the trailer.

The goal of this process is twofold:

  • eliminate rig waiting time and hot shot charges that are often associated with pulling a rod pump well. 
  • Improve safety on the well site by drastically reducing the number of suppliers and resulting unnecessary traffic.


8:00 – 8:30
Rod pump monitoring and optimization: new physics for today’s problems
Sebastien Mannai, Acoustic Wells

In reciprocating rod lift, dynamometric measurements are a well-established methodology to monitor downhole conditions, troubleshoot mechanical issues, and optimize operations. Since its early use in the 50s and the subsequent foundational work of Gibbs, this technology has become the gold standard of rod pump optimization, and many wells are now equipped with pump-off controllers (POC) that implement these principles in an industrial setting.
However, while POCs have achieved a high level of adoption on higher flow wells, they have mostly remained ignored on older, more marginal assets, such as stripper fields. And, while many operators do not focus primarily on such wells, their lease agreements, environmental liabilities, and the option value of holding acreage still compel them to operate large numbers of these assets. Today, it is simply impractical to instrument these wells with traditional POC solutions given the overwhelming infrastructure required and installation burden. As a consequence, operators of these assets mostly rely on manual surface inspections, leading to significant inefficiencies along with disproportionately high failure rates. Additionally, as the proportion of deviated wells increases, issues have been documented due to rod-tubing friction hampering the accuracy of traditional pump card analysis.
In this presentation, we introduce new developments, both in terms of sensing physics, hardware technologies and mathematical data processing, that reduce the cost of monitoring rod pumps by an order of magnitude to bring its benefits to new audiences, while complementing traditional POC setups to drastically increase accuracy in challenging environments.

8:30 – 9:00
The Status and Workflow of Artificial Intelligence for Artificial Lift
Patrick Bangert, Samsung

Artificial intelligence (AI) is a buzzword with a lot of hype but there are some genuine benefits that can be realized in the down-to-earth world of upstream oil and gas. This talk will briefly describe the status of AI in terms of what is realistic and what is hype. The workflow of an AI project will be discussed at a high level and put into context for artificial lift applications.

9:00 – 9:30
Impact of Ambyint’s Machine Learning Closed Loop Optimization System on Horizontal Bakken Wells: Failure Analysis Case Study
Arsalan Adil, Ambyint
Dr. Victoria Pons, Pons Energy Analytics

Failure rate analysis is a critical aspect of production engineering workflows that is conducted to evaluate the effectiveness of artificial lift designs, treatment programs and optimization technologies in order to determine where to drive operational excellence improvements. Methodologies to calculate Mean Time Between Failures and Failure Frequency vary between different operators leading to a lack of standardization across the industry. A robust, methodological approach to failure rate analysis is a critical need for operational success of artificial lift programs, the lack of which lead to higher operating costs and deferred production.

Ambyint’s production optimization solution utilizes an autonomous closed loop edge device which works with existing pumpoff controllers to gather data and uses cloud-based machine learning algorithms to remotely analyze and optimize wells. Based on successful deployment in the Bakken over the period of 3 years Ambyint has developed an objective methodology to quantify the impact of closed loop optimization on failure rates.

The machine learning model dynamically classifies the operating state of a well into three categories: overpumping, underpumping and dialed-in. Based on this classification, an optimization algorithm adjusts the speed set points of the variable frequency drive (VFD) and pump off controller (POC) to continually keep the oil well in “dialed-in” or optimized state. For wells that are under-pumping, Ambyint is able to increase oil production. Whereas for over-pumping wells, Ambyint is able to decrease the number of strokes and increase pump efficiency while maintaining production. The purpose of this autonomous optimization model is to operate wells at peak efficiency. Increasing production and pump efficiency significantly increases operator revenue. Reducing redundant strokes and detrimental pump offs is essential to extending the life of downhole equipment and reducing failures and therefore lowering OPEX.

This paper presents two different methodologies, which greatly increase the effectiveness of any failure analysis program. Unique to these methodologies is the inclusion of running lifespans. A ‘running lifespan’ is defined as the runtime of a well which has not failed at the time when the failure analysis is conducted. Running lifespans are usually not included in failure analysis, which results in inaccurate models since only wells that have failed are considered. This means that a well with a runtime of several years that has not failed is not included in the failure analysis, even if its runtime is greater than the previous runtime before the last failure. In this new approach, Mean Time Between Failures (MTBF) and Failure Frequency (FF) models are modified to include running lifespans and incomplete lifespans.

Results from the failure analysis study are presented with a scientific approach to quantify the impact of autonomous optimization and demonstrated the impact of such technologies to significantly improve Meantime Between Failures and Failure Frequency. Additionally, the paper outlines the workflow for structuring failure data, validating runtimes and correcting data anomalies before conducting failure analysis.

9:30 – 10:30

10:30 – 11:30
Keynote Speaker – Patrick D. Bangert

Artificial Intelligence and Machine Learning in the Digital Oilfield
How to use AI & ML to troubleshoot and optimize the operation of sucker rod lifted systems.

11:30 – 12:00
Panel Discussion
Topic: Artificial Intelligence and Machine Learning in the Digital Oilfield
Panelists: Rajan Chokshi, Patrick Bangert, Maggie Burns

12:30 – 1:00
Advances In Dynacard Acquisition And Processing: A Fully Autonomous Instrument
Gustavo Moreno, YPF

Author Block: G.A. Moreno; A. Garriz, A. Faccipieri, F. Sanchez, YPF Tecnología; M. Paura, A. Terlecki, M. Dos Santos YPF; F. Remersaro, EXEMYS

Objectives: Dynamometer data is the most important piece of information to analyze the downhole behavior of wells with beam pumps. State of the art instrumentation requires the installation of multiple devices and compute/communication units to compute the downhole card and communicate it to the SCADA. In this work we show how new techniques can used in a single fully autonomous device to do the same job, optimizing field deployment and reducing the instrumentation cost.
Methods:: The concept driving the design of the system was cost reduction. Measurements are based on accelerometer and load cell readings of the polished rod but, in contrast to other deployments in the literature, here we have developed a new set of numerical methods that allowed on the fly Fourier transformation, filtering and integration on board. These methods are the key to enclose both the sensors and the processing unit on a single device, achieving state of the art accuracy and full monitoring capabilities in a single compact unit.
Results, Observations, Conclusions: The benefits of integrating all the electronics on a single device have a sizable impact on the implementation cost. In this work we briefly explain the R&D process and field trials that guided the development of this new instrument. The system was specially targeted to low production wells, where instrumentation is many times is relegated.Field trials of this technology are analyzed in detail with excellent results for a wide range of situations such as full pump, fluid pound, plunger tagging and valve leaking. These examples show that this technology enables full instrumentation of the well in 20 minutes, which is a fraction of the typical operation intervention time for this kind o data acquisition systems. State of the art precision measurements and onboard downhole card inference are successfully demonstrated.
Novel: The system described in this work is a patent pending device that allows measurement, processing and diagnoses of sucker rod pumping units within a single apparatus. In this work we describe the technical advantages of the methods embedded in the unit and exhibit field cases of the technology implementation.

1:00 – 1:30
Discussion & Analysis of Field Pilot Results Using a Hydraulic Sheave Lock Versus Traditional Methods to Safely Lock Out Beam Pumping Units
Tracie Reed, Silverstream

This presentation will discuss a new method of locking out beam pumping unit using a patented hydraulic sheave lock that eliminates the need for workers to enter the swing zone, allowing personnel to accomplish lockout/tagout tasks safely and easily. The discussion will focus on findings from field pilots of installed hydraulic sheave lock units, including an analysis of the potential to reduce labor costs, third party service costs and traffic at the wellsite. It will compare the potential impact on field operations versus traditional methods of locking out beam pumping units, including time, safety & risk analysis, internal & external costs, and opportunities to streamline procedures.

1:30 – 2:00
Comparison of Corrosion and Wear Resistant Barrel Coatings and Their Failure Behavior Under Acidic Conditions
Pinar Karpuz, Don Nan

Surface coatings are commonly used in many industries including oil and gas with the aim of hardening the part surfaces to improve wear resistance without compromising the corrosion resistance. Sucker rod pumps employ several parts with coated surfaces as well, including the pump barrels. Both standardized surface modifications and specialty applications for pump barrels are readily available in the market for different well conditions, including extreme well solids and H2S or CO2 service. These service conditions can be detrimental for pump performance if the appropriate coating is not used. In addition, well treatment methods such as acidizing can deteriorate some coatings, reducing performance and in severe cases causing pump failures. This study focuses on the structure of 6 different standardized and specialty coatings on sucker rod pump barrels with an experimental study on their degradation in acidic environments, while familiarizing the reader with the recommended service conditions.


8:00 – 8:30
Conceptual Real-Time Digital Twin-Driven Sucker Rod Pumping Unit for Academic Learning and Commercial Applications
Catalin Teodoriu, The University of Oklahoma

In spite of Sucker rod pumps (SRP) being one of the most popular solutions for an artificial lift since their inception in the 19th century, Sucker rod pump failures are a common occurrence in oil and gas applications. Regrettably, the industry still lacks a system that can provide SRP health condition monitoring with the added capability of accurately predicting impending SRP failures. Presently, several industries are exploring the application of digital twins (DT) to optimize their process, make data-driven decisions in real-time, improve operational services, development and enhancement of new/old products and to have more efficient and safer operations. Digital twin technology is one of the main technologies related to Industry 4.0; an enhanced digital representation of a real system. This technology represents the biggest opportunity available today for performance optimization, avoidance of NPT, and hazard prevention. 

Despite DT considerable attention from the oil and gas field operators due to lower oil prices to reduce the downtime due to planned or unplanned preventive maintenance in the production field resulting to high operational cost (OPEX). The application and development of DTs for artificial lift systems are still in the early stages. Furthermore, digital twin technology is still not available and yet to researched, causing a technological and technical gap for petroleum engineering students and researchers. It is vital in engineering education that the curricula and the contents of the education are kept up-to-date including the educational environments.

This study presents a novel conceptual framework through application of a digital twin for sucker rod pump system intended for educational learning and commercial applications. The proposed SRP digital twin (DT) encompasses the physical component of a sucker rod field replica unit: our existing SRP oil field simulated well at MPGE-OU, digital versions of the SRP string, well fluids, among others, computational model, field senor data analytics by evaluating the occurrence and monitoring behavior SRP unit and failure prediction. 

The broader impact of this proposed project will enhance the knowledge understanding of petroleum students to accurately and automatically diagnose SRP operating conditions through digital learning. Furthermore, the results from this proposal will contribute and helps the industry to increase safety, improve efficiency and gain the best economic-value-based decision as well as reduce operational cost.

8:30 – 9:00
Mini-gas separators operating in parallel deliver >90% pump fill 24 hours a day.
Michael Kelly, Predator Tools

In this session we will look at the fluid dynamics of traditional downhole gas separators, and how their designs function to minimize gas interference. I will then introduce you to Predator’s latest advancements in downhole gas separator technology, and we’ll discuss how the Predator separator has delivered reduced well interventions, reduced gas pound, and increased production. We will also look at some specific installations and showcase the tool’s ability to consistently deliver >90% pump fill, 24 hours a day, in a wide variety of operating environments.

Attendees will get to see the basic design and a video of a Predator separator, and they will leave with a basic understanding of the strengths, benefits, and limitations of today’s popular downhole gas separators.

9:00 – 9:30
Optimizing Rod Lift VSD Wells Using Autonomous Control
Ramakrishna Prabhu Ranganathan, Weatherford

Rod lift well optimization is presented here using autonomous control to efficiently manage the speed of the pumping system to achieve target fillage and increased production. Autonomous control changes the minimum and maximum VSD speed setpoints while maintaining safe operating limits on both surface and downhole equipment.

Today on rod lift wells with VSD, Min/Max SPM or Frequency (Hz) are changed periodically, either by the Production Engineer and analyst using SCADA software or by the operator at Wellsite. The Production Engineer and analyst base their changes in the SPM on monitoring the well trends over a period of time.

On wells with varying inflow characteristics, an optimum VSD Min/Max SPM or Frequency (Hz) needs to be determined to maintain the desired target pump fillage.

On wells that maintain fillage above target pump fillage the Max SPM or Frequency (Hz) can be increased to achieve higher production after manually analyzing the well trends and performance. The increase is implemented in the controller only if the surface pumping unit system and downhole equipment design allows for it.

Existing controllers installed in the field today do not have the intelligence in place to autonomously increase the Max SPM by taking into consideration the safety factors of surface and downhole equipment. A manual change by an informed Production Engineer or well analyst is required for implementing such a change.

To find the optimum VSD Min/Max SPM and to increase Max SPM or Frequency (Hz) on the pumping unit, a rundown analysis of the well status data and safe operating conditional checks of surface and downhole equipment are needed to be performed before changing the SPM setpoints.

In this paper we will discuss how an Edge device, that has the capability to capture high frequency data, perform physics-based calculations on the data captured to ensure both the surface and downhole equipment are operating within safe operating limits, connected to an existing Rod Pump Controlled VSD system at the well site, can change the SPM or Frequency (Hz) autonomously. Using the analysis on high frequency data and physics-based calculations, Edge will autonomously change the SPM setpoints in increments on the Rod Pump Controlled VSD. The autonomous control performed by Edge is closed loop control logic, where the SPM setpoints are reverted back on the Rod Pump Controlled VSD if the surface and downhole equipment safe operating limits are exceeded at any time. Such a programmable closed loop autonomous control logic occurring on the Edge at the well site improves the run life of the equipment while maximizing the production in a safe manner.

9:30 – 10:30

10:30 – 11:30
Keynote Speaker – Siham Al-Habsi & Nawar AL Abadi

Diversity & Inclusion
Implementing best practices to provide equal opportunities in the oil and gas industry.

11:30 – 12:00
Panel Discussion
Topic: Diversity & Inclusion
Panelists: Susan Rosenbaum, Nawar Al Abadi, Siham Al Habsi, Larry Harms

12:30 – 1:00
Rod Pumping “Unpumpable” Wells
Mark Turland, Western Falcon & Weatherford

Unconventional producers challenged by low oil prices, continuously seek new opportunities to reduce LOE and increase profits.
Many new wells are initially equipped with ESP’s to achieve the high production volumes required. These ESP systems often experience short runtimes due to frac sand production and severe gas interference associated with producing new unconventional wells. The short runtimes combined with the high cost of ESP repairs force production engineers to closely monitor production volumes for the earliest opportunity to convert from ESP to SRPS.
Well depth, deviation/tortuosity and the high production volumes result in very high downhole friction in the SRPS contributing to pump, rods and tubing failures. For this reason, many wells are considered “unpumpable” with SRPS until production volumes fall below the 400-500 BPD range.
This presentation will demonstrate how combining new and existing SRPS technology can greatly expand the production range in these wells, up to 1000 BPD, while reducing equipment failures and increasing overall system efficiency.
The engineered design and application of these technologies will allow engineers to transition away from ESP to SRPS much sooner in the life of the well, resulting in considerable LOE savings and increased profits.

1:00 – 1:30
Enhancing Downhole Gas and Solids Separation and Lowering Operational Risk by Taking Advantage of Multiphase Flow Reversals
Jeff Saponja, Oilify

Objectives / Scope
Downhole separation of gas and solids for sucker rod pumping continues to be a significant challenge, particularly in horizontal wells. An advancement in downhole separation has been achieved by realizing there was an opportunity to intentionally take advantage of transient multiphase flow conditions where liquids and solids flow reversals exist. Multiple case studies in this presentation, demonstrate that taking advantage of multiphase flow reversals can enhance downhole separation performance and capacity, while at the same time lower operational risk.

Methods, Procedure, Process
Improving downhole separation without undesirably increasing operational risk and cost has been challenging. A separator design that requires a packer or annular seal, such as a cup, is inherently more operationally risky from an installation and retrieval perspective. Further, a separator design that impose pressure drops and/or increase flow turbulence face the risks of scale deposition, erosion, and reduced separation capacity due to turbulence worsening of the amount of entrained gas in the liquid.

It is generally understood that separation capacity has been physically limited by a separator’s cross-sectional area for separation. It is less understood that separation capacity has also been limited by the location and orientation of a separator’s intake, and that it has been limited by a common mechanical design practice of a concentric or centralized pump intake dip tube or mandrel.

Technical literature, industry research and transient multiphase flow simulations have revealed, under certain conditions, that multiphase flow reversals are not only present, but also occur at high frequencies. In a wellbore, after the onset of a flow reversal and during the liquids accumulation process, parts of the liquid phase in a multiphase fluid stream move upwards concurrently with the gas, and simultaneously, other parts of the liquid phase move counter-currently downward with the gas. In other words, parts of the liquid flow will frequently reverse direction from upward to downward. Counter-current flow reversal experiments observed that as the gas rate continues to decrease this partially-concurrent/partially-counter-current liquids behavior progresses up until the point where the liquid’s hydrostatic pressure gradient becomes zero (hanging liquid film field) and then after that point, the multiphase flow transitions to a fully counter-current liquid flow (i.e., net liquids flow rate is negative) leading to a maximum rate of liquid accumulation downhole.

Industry research has also disclosed that gas-liquid separation in an eccentric annulus is more efficient than in a concentric annulus. In addition, such research disclosed separation efficiency is greater an open top tube versus an annulus. Both of these separation efficiency benefits are due to the changes in the slip between various parts of the eccentric cross-section of the multiphase flow field.

It was hypothesized that such transient, ongoing, partial flow reversals could be taken advantage of  and in combination with the separation benefits of eccentric flow paths, downhole separation of gas and solids could be significantly enhanced in conjunction with lowered operational risks. A separator was then designed, built, extensively flow loop tested and successfully field implemented.

Results, Observations, Conclusions
This presentation describes the design process and results of the field implementation of an enhanced downhole separator that intentional uses transient multiphase flow reversals and eccentric flow paths. Flow loop testing results and comprehensive analytical transient multiphase flow simulation will be shared. A set of case studies, in multiple basins, reviews the field installations and presents the results of improved downhole separation performance, lowered operational risks, lowered Opex and increased production.

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Presenter Resources

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