2022 Southwestern Petroleum Short Course Schedule

Wednesday, April 20th

09:00AM - 09:50AM (Wednesday)

Room 101
(2022024) Field Trial Data Demonstrates Benefits of Advanced Metallic Coating that Actively Protects Rod Strings against Corrosion in Challenging Well Environments
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The objective of this paper is to share insights on mitigating sucker rod corrosion damage in vertical, horizontal and deviated wells with aggressive corrosive conditions such as H2S and CO2, particularly those with histories of corrosion-related rod/tubing failures.

Corrosion is a common problem in production operations, accounting for two-thirds of all rod string failures and costing billions annually to remediate, according to NACE International. This paper presents the development and initial field application results of a continuously applied metallic coating that actively participates in the electrochemical aspects of corrosion in carbon and low-alloy steels. Moreover, the solution protects uncoated segments of rod and other steel components in the wellbore while reducing abrasion by enhancing friction properties compared to bare steel.

The authors outline the key properties and characteristics of this coating, including evaluating its performance relative traditional corrosion protection measures such as barrier coatings. Rather than acting as a barrier layer, the metallic coating actively protects against corrosion and has inherent chemical properties that self-heal surface scratches and abrasions. This is particularly valuable in horizontal and directional wells with high dog leg severities and sideloading forces that contribute to rod/tubing abrasion.

Results are presented from laboratory testing as well as initial trial applications in wells with histories of rod failures due to corrosion, typically requiring interventions with workover rigs. In one such trial, the metallic coating was applied to a coiled rod string installed in a high-CO2 content well on progressing cavity pump. The coated coiled rod string was installed in January 2019. Ater five months of service, the coated string was pulled to inspect its condition. The examination revealed that the rod was unaffected by corrosion. A second inspection after nine months found evidence of rod string wear but no corrosion damage. The well has been in continuous operation for 35 months (and counting), more than doubling the average run time before installing coated coiled rod.

The novelty of this approach is the application of an advanced materials science coating to extend rod string service life in corrosive environments through active protection. In addition, it requires no special handling or installation equipment, and the metallic material allows rod strings to be recycled (eliminating potential environmental and downstream damage risks associated with barrier coatings).

As supported by lab and field case study data, the results of deploying this method include increased production uptime, reduced workover frequencies and associated remediation costs, and lower overall LOE and lifting cost per barrel of oil produced. 
 

Presented by:

Alex Perri and Angela Sultanian

ChampionX, Pro-Rod Coiled Rod Solutions

Artificial Lift Sucker Rod Pump
Room 102
(2022033) Plunger Assisted Gas Lift (PAGL) in the Permian Basin
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Plunger Assisted Gas Lift (PAGL) in the Permian Basin Over the last few years Gas Lift has become a popular artificial lift choice for producing unconventional wells in the Permian Basin. Gas Lift is a good choice for producing wells with high bottom-hole pressures (BHP) and high gas liquid ratios (GLR). Gas Lift is also a good choice for wells that produce solids or have deviated wellbores. Gas Lift however like all artificial lift choices has an optimum range which typically tends to be above five hundred barrels per day. When Gas Lift gets below five hundred barrels per day inefficiencies begin to surface with regards to the amount of fluid produced relative to the amount of gas injected. These inefficiencies can be addressed by running a hybrid system of gas lift and plunger lift to help maximize fluid production and minimize injection gas with the use of an interfacing tool known as a plunger that free cycles up and down the tubing and keeps gas from breaking thru fluid while flowing to surface. The system known as Plunger Assisted Gas Lift (PAGL) is becoming more popular and some operators have gone almost exclusively to this choice as Gas Lift wells begin to mature. This paper will highlight operators in the Permian Basin who have successfully integrated these systems into their long term production plans and review before and after production numbers, costs and estimated annual savings and increases to net revenue. The mechanical aspects of the system will be reviewed as well as installation and best operating practices. Additionally a preview of producing the well intermittently as it continues to decline by another hybrid system known as Gas Assisted Plunger Lift (GAPL) will be reviewed. 
 

Presented by:

Mike Swihart, PROLIFTCO

Artificial Lift Gas Lift Plunger Lift
Room 104
(2022034) Wireless Sensor Technology to Monitor Rod Rotator Performance
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Mechanical rod rotators have been used as part of the beam lift artificial lift system since the concept was first patented in the late 1930’s. By rotating the rods, the frictional wear surface can be distributed around the circumference of the rod, versus on a single side of the rod. By distributing the wear surface, the rod life will be significantly extended. In the same way, the industry has used tubing rotators to derive this same benefit on the tubing, distributing the wear around the inner circumference of the tubing. One of the biggest challenges associated with operating rotators is being able to confirm that proper rotation of the rods is taking place. The speed of rotation is very slow and is not easily observable without carefully watching the rods for several strokes, and often requires an observer to be very close to the rod string. Because of this challenge, the failure of a rotator can go undetected for long periods of time, which often results in premature failure of the rod system. This paper will explore some of the methods that have been used to monitor rod rotators, including some of the advantages and disadvantages of these methods. It will also introduce a new wireless sensor that is capable of remotely reporting not only the proper operation of a rotator, but also the actual speed of rotation, which is very useful to understand the rotator’s performance and to detect progressive failure. Field trial data was gathered as the algorithms were improved to eventually yield accurate monitoring capabilities. This data will be presented, along with several conclusions. This innovative sensor is adaptable to existing rotators, and can be easily integrated into existing pump-off controllers, so it is agnostic with respect to the manufacturer of the equipment and will have broad application for rod pump wells in the industry.
 

Presented by:

Terry Treiberg, Theta Oilfield Services-ChampionX
Justin Conyers, California Resources Corp. 

Artificial Lift Sucker Rod Pump
Room 106
(2022012) Evaluating the Use of Martensitic Steels for Sucker Rods
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The use of martensitic alloys in sucker rod applications has several significant advantages over ferritic-pearlitic alloys. Processing differences in making the different microstructures will be discussed, along with the resulting property and performance differences. An evaluation of the guidelines for optimal strength in various corrosive environments will be provided. Studies on the fatigue performance of martensitic and ferritic steels will be presented.
 

Presented by:

Joshua Jackson, US Corrosion Service

Artificial Lift Sucker Rod Pump
Room 107
(2022028) Reducing Rod Pumps Stuck in Tubing in The Highway 80 Field
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Abstract In 2019, we presented the early results of a design change on our insert sucker rod pumps in the Highway 80 field. The information presented previously was eighteen months of data after this change was made. We also included over seven years of data prior to the change. Today we will discuss the forty-eight months of data collected after the design change and more than 11 years reviewing sucker rod pumps stuck in tubing in this field. When an insert rod pump gets stuck in tubing, increases in well-servicing events drive costs and safety risks. The Highway 80 area team reviewed the number of pumps stuck in tubing from 2010 to July 31, 2021. There was a total of 1,159 insert rod pumps that could not be pulled with the rods to retrieve the pumps. Pioneer Natural Resources previously chose to use a rubber fin element below the discharge of their insert sucker rod pumps to prevent lodging from occurring. With this change, there was a reduction in pumps stuck in the tubing, but approximately 10% of their pumps continued to get stuck. In 2017, Harbison-Fischer installed their brush sand shield on all of Pioneer’s insert pumps in the Highway 80 field and continues to do so today. This paper will discuss the results of forty-eight months since the first brush sand shields were installed. We will compare the pumps that were stuck in the tubing with and without the design change since the implementation. 

Presented by:

Rodney Sands, ChampionX
Rowland Ramos, Pioneer Natural Resources
Matt Roam, TWS Pump 

Artificial Lift Sucker Rod Pump
Room 108
(2022040) Autonomous Chemical Optimization and Remote Monitoring: A Case Study
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With the development of new digital technology over the last several years, our industry has seen many benefits of remote monitoring and automation in sectors within drilling, completion, and production. One area that has lagged is remote monitoring and automation of production chemicals applications. This paper will review initial pilot testing of automated chemical pumps on a group of newly completed wells. The initial objectives of this pilot test were to 1) seek to identify potential chemical cost savings during the early life of the well by autonomously linking chemical injection rates to production volumes; 2) confirm that chemicals are being consistently applied at the prescribed dosages; 3) set up notifications alerting personnel of potential problems, such as low tank volume or inadequate power supply; 4) be able to use the historical chemical tank level data to assist in approval of chemical delivery invoices; 5) determine if operational efficiency of chemical vendor can be improved by needing to check tank volumes and pump rates less frequently; 6) help identify other applications in which this technology could be beneficial such as saltwater disposal chemicals or methanol injection for compressors. Methods, Procedures, Process: Automated chemical pump controllers with built-in communication devices are used to monitor and optimize chemical injection rates. The chemical pump controllers are then able to be remotely monitored and controlled using optimization software. A prescribed dosage target of chemical to production volume is assigned in the software where the software then calculates dosing rate each time a new well test is entered. The software sends the new dosing rate to the chemical controller. We also configured the software to send automated emails to the Well Optimization Analysts and the chemical vendor representatives to alert personnel of low tank volumes or low voltage issues. Results, Observations, Conclusions: The supply voltage would drop so low during the night that the pump would stop pumping. We had to upgrade our solar power system on certain wells to provide enough power to consistently achieve target chemical injection volumes. We then set up low voltage alarms so that we are immediately notified if there is a problem with the system. Also, by remotely monitoring tank levels and alarming on low tank levels we ensure that chemical deliveries are made on time. Another benefit from monitoring and trending tank levels is the ability to use the historical data to assist in confirming chemical invoices. Novel/Additive Information: Chemical programs have historically been controlled manually by a chemical vendor technician or operator on location in a reactive manner. Chemical tanks running dry, the loss of power, and lack of accountability can all be mitigated and resolved by automating chemical injection and enabling remote control. 
 

Presented by:

Dylan Bucanek, ChampionX
Jeff Clack, ConocoPhillips 

Prod. Handling
Room 110
(2022003) Impact from Analyzing The Run Life Statistics Using Survivability Curves Methodology On ESP Key Performance Indicators
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Managing extensive Electrical Submersible Pump (ESP) operations and evaluating their performance can be a challenging task, especially in unconventional reservoirs. Varied operational environments, expansive geographical areas, large ESP populations, different declination patterns, diverse fluid properties and well designs and different service providers are some of the complications that operators face every day. Many companies measure the success of any artificial lift project focus on simple run life statistics as the central key performance indicator; however, these types of statistics may not always be enough in providing significant information to decision makers. It is vital to the success of any project to establish a performance evaluation structure that can effectively capture deficiencies and highlight potential improvements. Survivability curves are the result of the statistical model based on Kaplan-Meier analysis, which was originally created to measure the fraction of subjects living for a certain amount of time after treatment in clinical trials, so similar methodology was deployed to analyze an important dataset of ESPs to deeper understand by factoring and comparing elements which influence ESP run life, showing results that are easier to understand and represent real value to operators on several areas as safety, engineering, reliability and operations. As a result, from this comprehensive study jointly initiated between an oil operator and ESP vendor, corrective actions were taken that drive improvements in all ESP aspects, which can be seen not only in today’s KPIs, also influence future artificial lift projects. Being able to draw conclusions about the expect runtime can be used to drawn insight on find areas where efforts should be focused to improve ESP reliability, find where ESPs can be best utilized to improve field performance, and identify opportunities to reduce workover cost. Similar analysis can be done to visualize ESP runlife improvement over time, compare different ESP technologies, and find expected runtimes by completion design or producing formation. The values of insights gained from statistical analysis can be gotten from any field of ESPs to aid in making better oilfield business decisions.

Presented by:

Christopher Bryan and Miguel Irausquin
Baker Hughes

Artificial Lift Electric Submersible Pump
Room 111
(2022019) Jet Lift Bridges Transition Gaps Between Various Forms of Artificial Lift in Horizontal Well Lifecycle
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The objective of this paper is to share insights from a case history of jet lift applications in the Permian Yeso play. Apache Corporation was among the first operators to deploy horizontal drilling and multistage fracturing in the Yeso formation in Eddy County, N.M., targeting dolostone/limestone/sandstone reservoirs interbedded with shale and anhydrite. The Yeso yields oil and liquids-rich gas at depths averaging 5,000-6,000 feet. Apache’s initial strategy was to commence post-flowback production from fractured wells with electrical submersible pumps, and then transition to rod lift as rates declined over time. However, as the wells approached the transition window between ESPs and rod pumps, high sand content and gas-to-liquids ratios caused frequent downtime for both types of lift, negatively impacting well performance. To counter these problems and accommodate the solids and GORs, the operator installed concentric string jet lift. This solution effectively bridged the application gap between high-rate ESPs in early well life and lower-rate rod pumps later in the lifecycle. Referencing the well data, the results section summarizes how jet lift operations successfully handled variable flow rates with high GORs / solids while achieving targeted drawdown and production output. The results demonstrate that jet lift improved uptime, maintained expected production decline, and reduced cost by eliminating frequent workovers to repair rod pump components. The novelty of this approach is the extended application range for jet lift, emphasizing its inherent flexibility in transitioning to different forms of artificial lift to meet changing production profiles as horizontal wells progress through their characteristic steep decline curves when faced with a deviated well that will increase rod-on-tubing failures and premature wear of the pump. The discussion synopsizes jet lift’s applicability across the lifecycle in horizontal resource plays, and the problem-solving benefits of concentric tubing string designs. The paper concludes with an assessment of jet lift’s evolving capabilities; specifically, how advancements in downhole sensors, remote monitoring / automation, and digital optimization are capturing value and enabling operators to deploy jet lift as an alternate lift system. 
 

Presented by:

John Massey, ChampionX 
 

Artificial Lift

10:00AM - 10:50AM (Wednesday)

Room 101
(2022031) Cost-Effective Solution to Corrosion-Induced Rod Failures
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When rod pump wells are operated in corrosive environments, corrosion induced sucker rod parts can lead to premature well failure and expensive, repeat workovers. Many corrosion mitigation solutions exist to combat this type of failure, including metallurgy, chemical inhibitor, and epoxy coatings, but they can be costly and not all solutions are appropriate for all types of wells.

In deep wells that require higher tensile rod strength, corrosion friendly metallurgy is generally not an option. In low producing wells, epoxy coatings may not be economically justifiable, depending on lead times and distance from a coating plant. Corrosion inhibitor can require constant monitoring to ensure the treatment is working and not all wells have an environment that promotes an even coating of inhibitor. 

In wells where traditional mitigation techniques have not been effective or economic, RodGuard has been successfully used to reduce the frequency of corrosion-induced rod parts. 
 

Presented by:

Kara Walling, NOV Inc. 

Artificial Lift Sucker Rod Pump
Room 102
(2022038) Downhole Sensors Support Successful Drilling Redesign Initiative in the Midland Basin
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The Midland Basin teaches a hard lesson in drilling harder rock. SM Energy first drilled there in 2008 before launching a successful horizontal drilling campaign in 2013. This work focuses on a successful application of the limiter redesign process supported with downhole sensors. Whirl suppression generates ROP performance improvements. This objective is complicated with a coupling to stick slip in hard rock applications. High WOB and therefore high torque tends to excite stick slip. Torque oscillations start, speed oscillations follow, and result in inconsistent DOC. Bit forensics on large wear flat shoulder cutter wear and delamination indicate high speed, friction, and heat damage under these conditions. This problem is explored in depth across the interbedded intermediate section of three pilot wells within the operator’s southern Midland Basin acreage. All three wells were drilled in a single bit run to TD and successfully cased and cemented by design. Three high frequency sensors recording at 100 Hz were installed in each BHA – one located in the bit, above the drilling motor, and at the drill collars. High frequency surface measurements were successfully tied to subsurface sensor observations. Good wellbore trajectory design, high ROP, and low planned dog leg severity positively contributed to weight transfer exceeding +97% based on WOB measurements in the BHA. Autodriller setpoint control and tuning unlocked ROP gains between 20-40% in the shallow hole section. MSE is reintroduced. Its practical value in baseline drilling surveillance and benchmarking is confirmed. The first well is treated as the control in the project. The trial starts with the common bit and BHA for the area with planned parameter step tests performed in each significant formation group. The second and third wells repeat the same workflow with progressive BHA changes to a single component. Depth of cut control is designed and utilized successfully on these wells to reduce torque oscillation. Roller reamers implemented on the final well act as a low torque stabilizer to increase useful torque at the bit. Torque stabilization and minimizations strategies must be paired with sufficient drill string stiffness to maximize performance impact in high WOB applications. The drilling performance initiative outlined in this paper is meant to be accessible to all drill teams and a call to action to redesign problems to the economic limit, forever. 
 

Presented by:

Ritthy Son, SM Energy

Drilling Operations
Room 104
(2022032) Understanding Rod Loading
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Understanding rod loading is vital to reducing failure rates in reciprocating rod lift systems. By changing the minimum stress and using the modified stress analysis instead of the modified goodman diagram, manufacturers are “tricking” you into using high tensile strength and/or premium sucker rods in your rod designs. This presentation will attempt to explain rod loading why most rod lift applications do not require or need  high strength and/or premium sucker rods.

Presented by:

Russell Stevens and Gary Abdo

Lufkin Rod

Artificial Lift Sucker Rod Pump
Room 107
(2022026) Troubleshoot Oil and Gas Wells Using Acoustic Level Shots
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Shooting fluid levels has become a well-known practice in support of daily production operations. The practice of shooting fluid levels is so well-known, in fact, that the term, “shooting fluid levels” is assumed to mean checking the fluid level to determine if a well is producing the maximum fluid potentially available from the formation. The most common use of an acoustic liquid level instrument is to measure the distance to the liquid level in the casing annulus of a well having a downhole pump. Shooting fluid levels inside the tubing (instead of just inside the casing annulus) is common practice in flowing gas wells. Fluid level both inside the tubing and inside the casing annulus is a valuable trouble-shooting technique used on wells that have either stopped producing altogether, or production rate has drastically decreased. Analysis of acquired fluid level shots can determine if there is a hole in the tubing. Tubing shots acquired at uniform time intervals can show ineffective pump operation, where down hole liquid level rise in the tubing occurs too slowly. Fluid levels shots are effective tools when troubleshooting oil and gas wells. Many fluid level examples will be presented that discuss how tubing and casing shots are acquired and analyzed to determine hole-in-tubing on all types of oil and gas wells. 
 

Presented by:

Lynn Rowlan and Gustavo Fernandez
Echometer Company

Artificial Lift Gas Lift
Room 108
(2022002) Optimizing Rod Lift Operations with Edge Computing
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Modern sucker rod pump operations rely on pump-off controller’s, surveillance dashboards, and human intervention to maximize production and pump performance. As a result, rod pump operations often suffer from high manual workload, limited diagnostics and dynamic well conditions. For wells fitted with pump-off controllers and variable speed drives, challenges remain around data gathering and evaluation. Bringing well specific insights to action requires continuous physical supervision to ensure well uptime. Edge computing and Internet of things (IoT) technologies offer high frequency data gathering, real-time evaluation and a reliable mechanism to maximize rod pump productivity while automating redundant tasks. Advanced computations, enabled by edge computing, allow for a more comprehensive analysis of pump conditions that compliments and surpasses the capabilities of pump off controller automation. This paper will demonstrate how closed loop algorithms deployed on edge computers work to ensure the best operating conditions, autonomous dynacard evaluation and interventions, and a proactive approach to help manage anomalous, high failure wells. 

Presented by:

Jared Bruns and Abhishek Sharma, Schlumberger 
Will Whitley, Oasis Petroleum 

Artificial Lift Sucker Rod Pump
Room 111
(2022009) A Revolutionary Packer Type Gas Separator That Involves G-Force to Exceed Traditional Gas Separation Efficiency In Oil And Gas Wells
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A revolutionary packer-type gas separator was designed to improve gas separation efficiency downhole. A deep analysis of gas separation methods was done to better understand the nature of the process and to design a tool that could generate enhanced conditions for the gas separation phenomenon. During the research stages where data from Permian fields were analyzed to develop this new design of gas separator, the engineering team found three main challenges in downhole gas separation. The first one was the wells were being converted from ESP to rod pump earlier, forcing the downhole gas separators to handle more production than before. The second is the small production casing size that usually is 5.5” casing, which significantly reduces the annulus area that is vital to get an effective gas separation efficiency, and finally, the gas slugging behavior, which in high proportion can lead to a gas lock-in sucker rod pump systems. Following the requirements and limitations, a packer-type gas separator was designed, built, and tested in oil wells. This gas separator has an outlet section of 1.89” OD, which means the design maximizes the gas separation area where it really matters at the fluid outlet point. The innovative fluid exit slots design creates a linear flow path allowing gas to separate and flow upward the casing annulus in a natural way. Additionally, a valve below the cup packer was included to eliminate surging in wells. This valve prevents surging by holding the fluid in the vertical section, thus avoiding backflow when the gas slug leaves liquids behind. To evaluate the new design, a calculator was developed to estimate the gas separation efficiency downhole and compare the gas separation efficiency among different gas separators. After the implementation of this design in 5 wells, the results confirmed the high gas separation efficiency obtained with this new gas separator configuration. The novelty of this gas separator design is the outlet section that takes advantage of the gravity force to increase the gas separation efficiency without limiting the tensile strength of the BHA. Also, the fact of including a valve to address the surging condition in the well before the fluids go through the gas separation is a new approach in a gas separation tool. 

Presented by:

Lee Weatherford, Gustavo Gonzalez, Luis Guanacas, and Donovan Sanchez
Odessa Separator
Michael Conley, Steward Energy

Artificial Lift Sucker Rod Pump

11:00AM - 11:50AM (Wednesday)

Room 101
(2022020) Artificial Intelligence and Automation for Surface Rod Lift Production
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Production performance monitoring has existed in Rod Lift Artificial Lift for decades, however there has lacked any action based on performance parameters. The Total Production Real Time (TPRT) Monitoring System incorporates data acquisition with artificial intelligence and automation to provide safer production operations for personnel and environment. TPRT collects live production data at surface on Rod BOPs, Stuffing Boxes, and Rod Rotators then drives actuation based on performance outside of expected performance parameters. For example, when a leak is detected at the primary seal for a Stuffing Box, TPRT engages a secondary actuator to recompress the seal, maintaining environmental control of the well during production as opposed to current product solutions which simply shut off the pumping unit at this minor inflection point on equipment performance. TPRT utilized point-to-point data acquisition and transmission to provide operators with live, cloud-based performance data on remote wells. The core functionality of TPRT is to maximize productivity while protecting from environmental leaks and limiting unnecessary visits to well sites.  
 

Presented by:

Joe Navar, Mesquite Technologies LLC

Artificial Lift Sucker Rod Pump
Room 102
(2022039) Vulnerability of Remote Monitoring and Control Systems in the Oil and Gas Industries
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Vulnerability of remote monitoring and control systems in the Oil and Gas industries By George Tyson and David Allen, Oiltek Systems LLC The Modern oil and gas industry extensively uses systems to remotely monitor and control operations throughout the process. Supervisory control and data acquisition (SCADA) systems have had wide acceptance and used for years. Many SCADA systems use the Modbus protocol, developed in 1979, to communicate between the parts of the system. Most of these systems operate under MS Windows or DOS. This creates an environment of ever expanding vulnerabilities. Hackers have used these vulnerabilities to wipe out revenue and destroy infrastructure. In 2021 Colonial Pipeline Co. had their major East Coast pipeline shut down by hackers. Hackers also broke into the water system of Florida City and tried to pump in a "dangerous" amount of a chemical and was only stopped by an alert employee. In a similar incident, in 2015 hackers were able to flick digital switches in Ukrainian power substations, causing cuts affecting hundreds of thousands of people. These vulnerabilities are growing. Every time MS Windows is updated there is a chance of a new vulnerability to be introduced into the operating system or in third party software. The new system that is entering service in the industry is the Internet of Things (IoT) or the Industrial Internet of Things (IIOT). The very nature of these systems allow them to be secured far better than SCADA and other legacy systems. This paper will examine the structure of IoT and IIoT to show how it contributes itself to security.

Presented by:

David Allen and George Tyson
OilTek 

General Interest
Room 104
(2022005) Remote Monitoring of Pressure Transient Acoustic Tests
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Data from acoustic fluid level and surface pressure measurements were acquired by a standalone programmable monitoring system that uses internet and cellphone communication with the Cloud for remote monitoring of pressure transient well performance. The system named Remote Asset Monitoring or RAM is described in detail in this paper that presents results from tests that lasted several weeks, beginning with well shut-in, continuing until pressure transient stabilization and afterwards during pump down until normal steady state production operation. The progress of the buildup test was monitored remotely by downloading the acquired data and reviewing the pressure trend with additional measurements acquired manually as needed. After buildup stabilization the pumping system was activated and during pump-down the fluid level, dynamometer, pressure, and motor power measurements were acquired automatically based on a user defined schedule. The combined results of the analysis were used to estimate reservoir performance and well productivity. In the past an operator was required to be at the wellsite to perform these tests. Once the portable RAM system was deployed at the well site and was programmed for standalone acquisition, the well performance trends were monitored wirelessly over extended periods of time without requiring an operator to return to the wellsite. When connected via the cloud, the data acquisition schedule was adjusted remotely and the stored data was viewed and retrieved as needed. Additional measurements were performed and interpreted in real time so that the operator was able to troubleshoot and analyze the performance of the well from any location in the world. 
 

Presented by:

Dieter Beck, Gustavo Fernandez, Ken Skinner, and Justin Bates
Echometer Company
A.L. Podio, Consultant

Artificial Lift Sucker Rod Pump
Room 106
(2022029) A Review of Heat-Related ESP Studies
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Due to the ESP motor’s inefficiencies, heat is produced when converting power from electrical to shaft power. This generated heat is either transferred to the surroundings (i.e., through the producing fluids) or absorbed by the motor. In the absence of proper cooling, the motor temperature keeps increasing until either the motor fails or it reaches a temperature high enough to transfer the generated heat to its surroundings. According to the Arrhenius rule, equipment life is expected to reduce in half for every 18°C increase. Proper heat transfer not only avoids overheating failures but also improves the system’s reliability. A survey of the open literature was performed to evaluate how the industry approaches the heat transfer problem for ESP motors. The studies were divided into six different categories. A recurrent approach is to enhance temperature ratings of internal components in the motor and perform field trials to verify an increase in reliability. Although this is a sound practice from a commercial point of view, it does not provide any insight. This review recovers simple theoretical models enabling a more fundamental understanding of ESP motor heat transfer behavior in complex scenarios. It also elucidates areas where knowledge is still lacking, particularly in two-phase flow conditions around the motor.

Presented by:

Vinicius Kramer Scariot, Eduardo Pereyra, and Cem Sarica
The University of Tulsa 

Artificial Lift Electric Submersible Pump
Room 107
(2022008) Gas Lift in the Lateral
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Horizontal wells are the largest capital investments made in the Permian and return on investment is essential. This project was developed to analyze the sustainability of gas lift as final form of artificial lift for unconventional horizontal wells. A pilot to run gas lift equipment deep into the lateral was developed, which involved meticulous candidate and downhole equipment selection. Two horizontal wells were selected, and deep gas lift was installed far into the lateral. 

Presented by:

Thad Gallegos, Sam Parks, and Anne Reese

ConocoPhillips

Artificial Lift Gas Lift
Room 108
(2022025) A New Approach to Safely Locking Out Pumping Units Using a Hydraulic Sheave Lock Versus Traditional Methods
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This presentation will discuss a new method of locking out beam pumping unit using a patented and engineered hydraulic sheave lock to support reducing risk at the well site when the pumping unit is shut down for routine maintenance or workovers. It will explore merits of keeping workers entirely out of the swing zone, allowing personnel to accomplish tasks safely and easily, without risk of brake cable failure or slippage resulting in movement of the counterweights. The discussion will focus on how this approach impacts traditional operational practices including an analysis of key metrics encompassing the ability to reduce third party service costs, avoid near miss and serious safety incidents, while also reducing traffic at the well site, resulting in less road damage and carbon emissions. Discussion will focus on how this new process adds value by reducing costs and improving safety for producers. 
 

Presented by:

Tracie Reed, Silverstream Energy Solutions Inc. 
Don Foley, and Kurt Richard, KUDO Energy Services 

Artificial Lift Sucker Rod Pump
Room 110
(2022014) Management of Gas Slugging Along with Sand Handling to Improve ESP Performance and Efficiency
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A dual purpose design is presented in this paper to face high gas presence and sand production conditions in petroleum wells with an Electric Submersible Pump (ESP) system installed. The results of this design’s application in severely problematic wells, due to high gas and sand production, will confirm the importance of conditioning the fluid before it gets to the pump intake.

This engineered design consists of different stages from the isolation of the pump intake until the tubing bodies in charge of gas and sand handling. Engineering concepts were applied in the construction of this solution such as gas re-solubilization, changes of pressure and velocity, agitation, and vortex effect to finally present a design that is capable of breaking gas slugs into smaller gas bubbles that can be produced by the ESP system without impacting its performance, and at the same time separating fine solid particles (<250 microns) using centrifugal forces.

Case studies from wells located in the Permian basin will better explain the positive impact of selecting a proper downhole conditioning system to improve the ESP systems efficiency. A drastic improvement on the sensor parameters will also illustrate the effect of handling the gas and sand before the pump intake, which also leads to one of the most important consequences: A decrease in the number of shutdowns, which in turn decreases non-productive time, resulting in positive impact of fluid production. Additionally, the flexibility of this design is significant, since it allows it to be installed in a wide range of fluid production, gas-liquid ratio, tubing and casing sizes.

The novelty of this new design is the addition of the surge valve below the packer, which accomplishes multiple purposes: to avoid surging in the well, to allow testing the packer to assure it is properly set, and finally, allow chemical injection below the packer.
 

Presented by:

Neil Johnson Vazhappilly, and Gustavo Gonzalez, Odessa Separator, Inc. 
 

Artificial Lift Electric Submersible Pump
Room 111
(2022023) The Silver Bullet: Overcoming Gas Interference In Unconventional Rod Pumped Wells
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With today’s highly dynamic unconventional wells, gas separation is essential after the conversion from electric submersible pumps (ESPs) to rod lift. Unconventional wells in the Permian Basin have high initial rates with steep declines rates, which result in a high gas-to-liquid ratio very early in the life of the well. As the reservoir pressure draws down below bubble point pressure, increasing volumes of free gas begin to break out of solution. This results in downtime due to erroneous attribution of well condition to pumped off in a critical time when aggressive fluid extraction is needed. Better well optimization is achievable through proper gas separation to maximize production and minimize downtime. Common solutions to this problem involve the use of Mother-Hubbard or packer style separator, which are not always adequate for the task and can be easily overrun by gas. Additionally, if the well is pumped too aggressively, the gas separators can be overrun by production, meaning minimal gas separation occurs. Combining the efficiency of the industry’s leading packer style gas separator, a patented shroud and the new innovative technology of the bypass tubes from the ESP Gas ByPass, the Silver Bullet maximizes gas separation using two pathways for gas separation to occur. Using the Silver Bullet increases total production by both ensuring that the pump is full and by reducing the amount of time the well spends idle. Furthermore, decreasing the number of gas interference events helps reduce failure and increase the life of downhole equipment. Less gas interference in the pump leads to longer run times, more consistent pump fillage and ultimately more revenue. This paper details the technology behind the Silver Bullet and presents case studies proving tool efficiency. 
 

Presented by:

Russell Messer and Matt Raglin
WellWorx Energy Solutions

Artificial Lift Sucker Rod Pump

01:00PM - 01:50PM (Wednesday)

Room 102
(2022030) Unconventional Results with Conventional Long Stroke Rod Lift Systems: A Study of Design Process and Results Produced in Various Applications
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Sucker rod pumping is largely regarded as the final artificial lift method in a well’s lifecycle. Until now, the industry standard application of sucker rod pumping systems has been up to 400 barrels per day fluid production. With the industry advancing towards deeper wells and increasingly aggressive production targets, the challenge of meeting these application parameters while decreasing costs has become forefront to an operator’s requirements for profitability and in some cases, survival. To meet this need, Lufkin has established a system design comprised of a novel conventional 2560-500-320 pumping unit and fit-for-purpose rod string and pump, coupled with the ability to accurately control performance with automation. Through a comprehensive design analysis which factors in well characteristics, operational preferences, and production requirements, a system was developed to optimize production while minimizing lifting costs for operators. This approach has proven to lower or eliminate capital and operating costs for oil and gas producers by reducing the number or types of artificial lift methods, increasing fluid production, reducing failures, and lowering workover costs, as compared to other artificial lift methods or different pumping unit types. This paper will review design objectives, challenges, predictive analytics, implementation, economics, and the application results ranging from 400 to over 1000 barrels per day of fluid production achieved. 
 

Presented by:

Trey Binford and Lauren Silverman
Lufkin Industries

Artificial Lift Sucker Rod Pump
Room 104
(2022037) The Downstroke Pump and Special or Unusual Sucker Rod Pumps Explained
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The Downstroke Pump and Special or Unusual Sucker Rod Pumps Explained This paper will explain the author’s theory of operation of the pump that lifts fluid on the downstroke, using the weight of the rods, and its loading of the sucker rod string and pumping unit. Other special sucker rod pumps will be likewise explained, using the author’s understanding, including the family of double displacement type pumps, compound compression ratio pumps, traveling barrel pumps, and others. Also discussed will be the loading changes incurred when some of these pumps are configured in the top hold down, bottom hold down or tubing pump configurations. 
 

Presented by:

Benny Williams, Q2 Artificial Lift Services

Artificial Lift Sucker Rod Pump
Room 106
(2022017) Downhole Sucker Rod Sensor – Mystery Solved
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With the increase in the number of horizontal wells drilled in the past 15 years, the technology for predicting downhole conditions and troubleshooting problem wells has not kept up with the increased complexity of these deeper and deviated wellbores. The systems in use are no longer accurate or sensitive enough to determine what is causing the problem(s) resulting in shorter meantime between failure and higher workover cost to the operators. To unravel the mystery we introduce the Downhole Sucker Rod Sensor which measures what is happening downhole and enables the customer a systematic approach to troubleshooting and therefore reducing the number of failures while providing a method for measuring the effectiveness of new and existing technologies. These sensors can be strategically placed anywhere in the rodstring and collect high-resolution measured data for pressure, temperature, torque, compression, velocity and position. In addition to generating a high resolution measured downhole DynaCard that can distinguish sync issues with different strokes per minute (SPM). The data is used to uncover issues with string wear i.e. alignment or sync issues, friction, pump and tubing issues as well as calculated values for specific gravity, pump fillage, and pump intake pressure. The main objectives are summarized as follows: o Comparing actual Downhole DynaCard measurements to the Surface and the Predicted Cards o Maximizing reservoir drainage and production optimization o Identifying, isolating and optimizing mechanical issues in problem wells o Measuring the impact of new and existing technologies (such as guides, friction reducers, …) and their effectiveness in extending the service life of the SR system. o Verify if rod guides, friction reducers… are adding value and not just cost! Vision: o Utilize sucker rod sensor(s) on problem wells and convey lessons learned to other wells. o Improve the software systems currently calculating downhole dynagraphs. o Improve the accuracy of (surface) software calculations which will yield improvements for a large number of unconventional wells. o Provide our Customer’s with a competitive advantage. 
 

Presented by:

John MacKay, Stian Slotterøy, Rutger Suermondt, Paolo Santos - Well Innovation 
Keith Fangmeier, Cedar Ranch Consulting 

Artificial Lift Sucker Rod Pump
Room 107
(2022027) NON-CABLE Actuated Rod Rotator: Technology Development and Field Experiences
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The use of rod rotators is key to extend the life of sucker rod string couplings in all intentionally and not intentionally deviated wells. Its applicability has proved to be a low-cost solution, giving an even wear on sucker rod couplings, extending considerably their run time.
One of the major issues with conventional cable actuated rod rotators is the integrity of the cable, its installation and proper maintenance. It’s common to heard from operators losing the cable connection and ending up on a premature failure on sucker rod couplings due to localized wear.


Initially designed as a solution for long stroke belt driven units, where cable rod rotators weren’t reliable, a telescopic arm actuated rod rotator solves the issue with minimal down time. This innovation then was implemented in conventional pumping unit setups providing reliable rotations of sucker rod strings.


This paper describes the development process for the telescopic arm actuated rod rotator and the case studies in their initial set of applications in operation.
 

Presented by:

Nicolas Guyubas, Martin Ruiz Palero, Daltec Oil Tools
Rodrigo Ruiz, Duxaoil Texas LLC

Artificial Lift Sucker Rod Pump
Room 108
(2022004) Applying Data from Fluid Level Shots to Optimize Chemical Treatment Programs
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Data from fluid level shots can be very valuable in optimizing the chemical treatment program. For example, selecting continuous treatment vs truck treatment, adjusting flush volumes on truck treated wells, ensuring slip-streams are open and adequately slipping, or raising the SN depth on wells that cannot be pumped down. Just because chemical is being introduced into the backside does not mean it is effectively getting downhole, or getting downhole at all. This is especially true with flumping wells that are particularly hard to treat without a cap-string (although operators often apply cookie-cutter treatments for the whole field without taking individual well differences into account). Different methods of introducing chemical into the well and ways to overcome chemical treating challenges will be discussed and tied into how data from fluid level shots can help guide better decision making.

Presented by:

Shawn Dawsey, Downhole Diagnostic

Artificial Lift Sucker Rod Pump
Room 110
(2022011) Cenesis Phase System for High Gas ESP Applications
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Electric Submersible Pumps (ESPs) are severely affected by free gas entering the pump, which cause significant degradation in pump performance, due to gas locking conditions cause by bubbles blocking the fluid from passing through the impellers, resulting in frequent shutdowns and restarts, which increase the risk of early failure. This effect is even worst when a gas slug event, very common in horizontal wells drilled in unconventional reservoirs, hit the system, this event consist of a large volume of light density fluid (gas) flowing through the system, overheating the motor and pumps due to a no liquid flow condition, resulting in unstable production due to ESP shutdowns caused by underload or high motor temperature. The industry has used shrouds, rotary and vortex gas separators, and more recently, multiphase pumps to handle the gas, however, there are some applications where this equipment is not enough to handle the Gas Liquid Ratio (GLR). Recently two Oil Operator Companies in the Permian basin following our recommendation successfully installed a multiphase encapsulated production solution technology to separate the gas from the liquid in the wellbore. As produced fluids, pass the pump at high velocity, the heavier liquid falls back into the shroud in a low-velocity area between the tubing and the top of the shroud, allowing the gas to continue to the surface. This system has proven to separate the gas from the liquid effectively (> 90% of efficiency), stabilizing operations within a certain operating window. In this document, results are shown for two successful field cases, how uptime improved, being able to reduce the number of shutdowns, improving operational performance and increase the drawdown maintaining stable production of the wells. 
 

Presented by:

Miguel Irausquin, Mohammad Masadeh,  Nelson Ruiz and Oswaldo Robles
Baker Hughes 

Artificial Lift Electric Submersible Pump
Room 111
(2022010) New Mechanism of Sand Management Above ESPs
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Extending the run life of wells with Electrical Submersible Pumps (ESP) becomes a crucial need since it is one of the most economically expensive types of ALS. Following the need, a sand regulator has been designed to protect the pump during shutdowns, and it has been incorporated into traditional sand control configurations to offer extensive protection above and below the pump. This paper will explain the mechanism of the sand regulator as well as the benefit of installing this system alone above the pump or complemented with a sand control system below the pump. Since the wells had sand problem history and it was necessary to review pump designs, pulling reports, and sensor parameters along with well conditions such as production, tubing size, and particle size distribution were analyzed to build the best design for every single well. In the design, the geometry of the well was assessed to accommodate the cable and CT line downhole. The Acordionero Field is characterized by heavy oil production (400-1000 BFPD), with a viscosity of 430 cP @ 150°F, API between 13-15, low water cuts (Between 3.9% to 20%), and high fine sand production (3000 - 5000 ppm). Cohembí Field wells produce between 1000 - 6000 BFPD, with API between 17-18, high water cuts (> 77%), and a high sand production between 500 - 3000 ppm. The wells selected had other types of sand control and management systems and were highly affected by frequent shutdowns. The Sand Regulator design was installed on 20 wells and was compared with the performance achieved using traditional sand control solutions. After the installation, production has remained stable in all the wells applied, allowing to reduce the PIP of the well from 900 psi to 500 psi. Less current consumption has been observed after each shutdown in all the wells, extending the run life of some wells from 108 days to more than a year. Sensor parameters were analyzed after each pump restart to determine how difficult it was to restart operation after shutdowns. Compared to the tools installed above the ESP, this sand regulator allows flushing operation through it with flow ranges from 0.5 to 5 bpm. In addition, the unconventional design of this tool has opened the door to a new concept of ESP protection that works in wells with light or heavy oil and can be refurbished or inspected completely without cutting the tool.

Presented by:

Anderson Delgado, Jorge Espinosa, Gran Tierra; Luis Guanacas, 
Gustavo Gonzalez, and Carlos Portilla, 
Odessa Separator Inc.
 

Artificial Lift

02:00PM - 02:50PM (Wednesday)

Room 101
(2022007) Decreasing Tubing Wear From Sucker Rod Coupling In Deviated Wells
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In a reciprocating rod lift application, production tubing failure due to metal-to-metal contact with sucker rod couplings is a common problem in the highly deviated sections of the tubing string. The coupling is forced to be the point of contact against the tubing wall, which causes high friction and excessive tubing wear during the reciprocating motion. This excessive tubing wear typically leads to a hole in the tubing wall, resulting in high workover costs for the producer.  The coupling surface hardness, roughness, and coefficient of friction between the coupling and the tubing are all directly related to the resulting tubing wear generated at the contact region.  This paper intends to show through both in-house laboratory testing and preliminary field results that applying a lower friction coating to a sucker rod coupling decreases tubing wear and increases the life of the string. 

Presented by:

Justin Galle and Christopher Lauden
Weatherford 

Artificial Lift Sucker Rod Pump
Room 102
(2022036) Continuous Rod Scanning Using LV-EMI™ Proprietary Technology
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Rod pumping unconventional wells is becoming increasingly challenging due to unpredictable downhole environments. Many unconventional wells exhibit significant deviation accompanied with corrosion making them difficult to rod lift without exposing downhole equipment to unpredictable damage mechanisms – specifically the rod string.

Continuous rod is a proven technology in these deviated unconventional wells as it increases the mean time between failures through lack of connections and distributed side loads. Although continuous rod will increase the mean time between failures, all rod pumping systems will eventually require an intervention. Traditionally, when continuous rod is pulled during a workover, inspections have been done visually in the field by experienced rig crews. However, this method is imprecise and subject to human error. This can result in unexpectedly early failure after a satisfactory inspection or additional cost from replacing mechanically serviceable continuous rod strings.

The Low Voltage – Electromagnetic Inspection (LV-EMI™) unit will detect three-dimensional discontinuities and cross-sectional loss in semi-elliptical and round continuous rod strings.  In this paper, the continued development of this new technology and the results from two semi-elliptical continuous rod string scans will be presented. Proposed future enhancements resulting from preliminary field tests will be identified.

Presented by:

Enio Oliveros, L.J. Guillotte Jr., Anne Marie Weaver, and Blake Vacek, LPS
Jared Jensen, Chevron

Artificial Lift
Room 104
(2022042) Leveraging Best Practices to Maximize the Value of Automation Systems and Optimization Software
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There are three components to a successful rod lift surveillance and analysis program. One, a rod pump off controller is needed to match inflow to outflow, reduce fluid pound when configured properly, and to shut the well down in the event of a downhole failure. Secondly, a host system is needed to provide immediate identification of downed wells, remote surveillance, and the ability to monitor and analyze hundreds of wells per day, enabling quicker identification of variances and solutions. And lastly, and of equal importance is to establish and implement business rules, work processes, and best practices that leverage the pump off controllers and host systems. In today’s world of ‘do more with less’, all three steps are needed to realize the full benefit of automation, and to achieve full optimization. Operators tend to spend the upfront dollars, which is by far the majority, for the hardware and software, but oftentimes never realize the full benefit due to not dedicating the resources, training the employees on technical Well Analysis, and implementing the supporting business rules, work processes, and best practices. The presentation will describe a situation in which a company utilized pump off controllers and a host system, but were lacking the business rules, work processes, and best practices to complement the hardware and software. The company leadership recognized gaps in skillsets, missed opportunities, and basic lack of understanding of the value of automation, and engaged ChampionX to do an assessment, or ‘health check’ of their fields and wells. A clear before and after picture of the metrics will be shown in the final paper. Below were the initial steps. 1. Both parties met to determine which metrics were to be measured, and acceptable targets/ranges. Below is a sampling of the individual metrics to be measured. a. Number of wells in some state of alarm. b. Wells cycling excessively. c. Wells with low volumetric efficiency due to over pumping or loss of displacement. d. Wells in need of additional lift capacity. e. Wells running with excessive SPM. 2. ChampionX Consultant mined, assembled, and presented the data to core team within said company. Each metric received a score. 3. Company Leadership presented findings and results to broader audience within Company operations. 4. The metrics and targets were adjusted where needed. 5. Workflows were built for each metric outlining the specific steps to take describing ‘how’ to improve the score. 6. Business rules were established for each metric describing ‘who’ and ‘when’ various steps are to be taken. 7. Each metric was assigned an ‘owner’. 8. The status of each metric is publicized daily via internal dashboard. With this exercise, it was immediately apparent to the company’s leadership team, and other personnel that the ROI on their automation system was significantly lacking. The presentation will show the value gained from implementing the third piece of the process. 

Presented by:

Brett Williams, ChampionX

Prod. Handling
Room 106
(2022021) Autonomous Control of Well Downtime to Optimize Production and Cycling in Sucker Rod Pump Artificially Lifted Wells
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For decades sucker rod pump artificially lifted wells have used devices called pump off controllers (POC) to match the pumping unit’s runtime to the available reservoir production by idling the well for a set time where variable frequencies drives are not available. In doing this the POC allows the well to enter a set period of downtime when the downhole pump fillage is incomplete to avoid premature failures, and then brings the well back online to operate before production is lost. Although this method has been successful for several years, autonomous control algorithms can be utilized to reduce failures or increase production in cases where the downtime is not already optimized. Optimizing the idle time for a sucker rod pump artificially lifted well involves understanding the amount of time required to fill the near wellbore storage area before generating a fluid column above the pump intake that will begin to hinder inflow from the reservoir into the wellbore. By varying the idle time and observing the impact on production and cycles the program hunts for the optimal idle time. By constantly hunting for the optimal idle time the optimization process can adjust the idle time when operating conditions change. This gives the advantage of always meeting the current well bore and reservoir conditions without having to have a user make these changes and determine what the downtime for the well is. Autonomously modulating the idle time for a well, if done properly will either reduces incomplete fillage pump strokes, in cases where the idle time is too short, or will increase the wells production in cases where the idle time is too long. Overall this will result in the optimization of wells by reducing failures and/or increasing production, generating a huge value to the end user by automating the entire process of downtime optimization.
 

Presented by:

Ian Nickell, ChampionX

Artificial Lift Sucker Rod Pump
Room 107
(2022001) Tubing Back Pressure on Rod Pump Wells
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One of the most misunderstood issues in sucker rod pumping is tubing back pressure. The great majority of wells that I have encountered in various fields have back pressure valves installed on the tubing side of a wellhead. However, a great many field personnel do not understand why back pressure is applied, how much to apply, and/or how it affects a well’s performance. This paper will discuss the why, when, and how tubing back pressure is applied along with some misunderstandings and issues of its application. 

Presented by:

Mike Brock, PLTech, LLC

Artificial Lift Sucker Rod Pump
Room 110
(2022016) Comparison Of Corrosion/Wear Resistant Barrel Coatings And Their Failure Behavior Under Acidic Conditions
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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 -or even improve when applicable. 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 market for different well conditions, including extreme well solids and H2S and CO2 service. These service conditions can be detrimental for pump performance if the right coating is not used. In addition to service conditions, well treatment methods such as acidizing can also deteriorate the coating performance, causing pump failures. This study focuses on the structure of 6 different standardized and specialty coatings on sucker rod pump barrels and an experimental study on their degradation in acidic environments, while familiarizing the reader with the recommended service conditions. 
 

Presented by:

Pinar Karpuz-Pickell and Levins Thompson
LUFKIN Don-Nan

Artificial Lift Sucker Rod Pump
Room 111
(2022013) The Case Study of Applying Field Data By Utilizing Pressure And Temperature Survey Results And Winkler’s Valve Performance Analysis To Optimize Production In Gas Assisted Plunger Lift (GAPL)
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This case study has a completion with 2-7/8” tubing in 5-1/2” casing without a packer, with 8 IPO gas lift valves in conventional mandrels with an orifice as the last valve and a chemical screen below that. A grooved plunger was used in this well in combination with gas lift to reduce liquid fall back losses and provides a solid sealing interface between the liquid slug and the gas below it. The liquid rate declined drastically after operating the well on the gas lift at 600 MCFD rate and 1050 psig injection pressure for eight months. The well did not recover after trying several combinations of lift gas volume and plunger speed. As the lift depth in gas lift system depends upon the intersection point between surface injection pressure and multiphase flowing gradient. The pressure and temperature survey with resistance temperature detector (RTD) sensor has been run till the heal of the well at a stabilized injection gas flow rate along with wellhead recorders, recording casing and tubing pressures and temperatures for the entire duration of the survey. This process will help determine the lift point by identifying the Joules-Thompson cooling effect on the temperature curve. And it will also help sense the maximum and minimum pressures if the well is heading (surging or slugging) by keeping the wireline gauges at each depth for sufficient time. The methodical approach of creating a bridge between gas lift design and pressure-temperature survey interpretation gives operational insights into what was wrong with the gas lift operating envelope. The injection pressure endpoints are generated after performing a well-delivery analysis simulation with lower bottom hole pressure (revealed from the survey). And by utilizing Winkler’s gas passage analysis, the gas rate through designed port sizes in gas lift valves can be simulated, which is required for the existing deliverability of the well. Recent changes in operating conditions were proposed after performing several simulations on downhole flowing pressure and temperature at changing injection rates to measure the decrease in production. And applying these new conditions backed by the well’s data brought the well’s production back on the curve. This case history shows the complete scheme of creating an effective lift gas troubleshooting matrix in gas lift systems from concept initiation to execution and field installation. 
 

Presented by:

Haseeb Janjua, PROLIFTCO

Artificial Lift Gas Lift

03:30PM - 04:20PM (Wednesday)

Room 101
(2022041) Value Of High-Resolution Data In Production Engineering
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Today, a good upstream or production engineer must understand the running condition of every well of which he is in charge in order to optimize production & profitability, usually by adjusting various setpoints. Typically, he will use data recorded by a pump-off controller (POC), fluid level shots, etc. as well as often coupling this wellhead-level data with intermittent information from stock tanks or test batteries.
To make things more complicated, most of the data generated by sensors on a field stays on the field controller’s local memory with just a select few data points actually transmitted (via low-bandwidth SCADA) to a host server and made readily accessible to engineers. Typically, this system is just capable enough to allow an engineer to diagnose crude issues and major failures. More modern systems send data to centralized control rooms far from the field, almost always unstandardized and unsanitized – as a result, more data sent means more man-hours needed to actually parse and analyze it which often falls by the wayside. In addition, it is often impractical to fully instrument a field with traditional automation solutions given the overwhelming infrastructure required and installation burden. As a consequence, most operators rely on incomplete data, leading to significant inefficiencies along with high operating costs.
In this presentation, we introduce state-of-the-art developments, both in terms of hardware technologies and mathematical data processing techniques used to automatically interpret data, as well as how these developments effectively leverage data points across the field to (1) reduce the cost of monitoring assets by an order of magnitude, making it affordable for lower flow legacy wells, (2) remove the need for routine in-person inspection of leases, and (3) increase production and equipment life-time while reducing power consumption through optimization.

Presented by:

Charles-Henri Clerget, and Sebastien Mannai
Acoustic Wells 

Prod. Handling
Room 104
(2022006) Cloud Based Monitoring of Pumping Well Performance
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Data from fluid level, dynamometer, pressure, and motor power measurements were acquired by a standalone programmable monitoring system that uses internet and cellphone communication with the Cloud for remote monitoring of well performance. The system named Remote Asset Monitoring or RAM is described in detail in this paper that presents results from the tests that lasted several weeks, beginning with well pump down, just after new pump installation and continuing during normal production operation. The performance of the well was monitored in detail and additional measurements were acquired as needed based on the real time performance of the pumping system. 

In the past an operator was required to be at the wellsite to perform these tests. Once the portable RAM system was deployed at the well site and was programmed for standalone acquisition, the well performance trends were monitored wirelessly over extended periods of time without requiring an operator to return to the wellsite.

When connected via the cloud, the data acquisition schedule was adjusted remotely and the stored data was viewed and retrieved as needed. Additional measurements were performed and interpreted in real time so that the operator was able to troubleshoot and analyze the performance of the well from any location in the world.

Presented by:

Gustavo Fernandez, Dieter Becker, Ken Skinner and James N. McCoy
Echometer Company

Artificial Lift Sucker Rod Pump
Room 107
(2022018) End-to-End Rod Control - Predictability in the Rod String
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Black Mamba Rod Lift’s helical centralizer stabilizes the rod string during pumping chaos. Chaos is understood as sucker rod buckling and negative loading (compression), which is impossible to eliminate in beam lift wells. The source of compression is often from nature (gas interference, fluid pound, gas pound) but can be operator induced (seating the pump, pump tagging), or compression as part of the pumping method and operation (pump friction, fluid load transition). When compression occurs on standard slick or guided sucker rod, rods experience bending moments, or focused points of high stress leading to micro-fractures which propagate and lead to rod parts. Multiple operators big and small have tested and validated Black Mamba’s system design. By April 2022, we will have had product tested and deployed for nearly 24 months. Operators elect to use Black Mamba for standard guide replacement, but most often opt for Complete, Predictable, End-to-End Rod Control (7 Black Mamba guides per rod), eliminating instability and providing a drastic increase in rod string reliability and rod string life, increasing MTF dramatically. The implementation of rod string stability is most often found at the bottom of the rod string where compression is most prevalent, working upward. Often 3/4" rods have been removed from system and string design due to their low AMOI and increased tendency for buckling. With constant centralization, 3/4" rods take compression and never buckle, following tubing exactly. Sinker Bar replacement is common in deviated horizontals, with the industry transitioning to guided 1” or 7/8” rod body with 3/4" pin connection (reduced coupling diameter allows for extended guide life). This product offering is provided to industry by multiple manufacturers, Black Mamba doing so in Permian, Bakken, Mid-Con. Utilizing 7/8” Slim Hole Couplings (with proper derating) is a good idea for extending rod guide life and extending the time-to-first-contact between coupling and tubing. 1” Slim Hole Couplings are so large they practically render rod guides useless for 1” rod body with 1” pin connection. We discourage the use of standard 1” pin connections when possible. Hybrid sucker rod products are available and actively promoted – 1” HA/HS rod with 7/8” connection reduces coupling diameter, maintains pin-connection strength, and will extend time-to-first-contact between coupling and tubing. Designing rod strings with chaos expected is an ideal method for ensuring the rod string is buckle-proof and ready for any source of chaos, operationally driven or nature driven. Compression Control Rod String Design considers all drivers of instability; the rod string can operate without bending moments, preventing a driving force of pre-mature sucker rod fatigue. Black Mamba’s installations have increased habitual failures by 6x (last 8 failures were at 3 months each), allows operators to pump 192” stroke units at 10 SPM reliably, and removes all guess-work out of string design. Product will have been deployed for nearly 2 years across the world in a variety of pumping conditions. 

Presented by:

Jonathan Martin, Black Mamba Rod Lift 
 

Artificial Lift Sucker Rod Pump
Room 108
(2022022) Collaboration In Developing a New Guide Material For West Texas Rod Lifted Wells
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Failures due to Rod wear and tubing wear account together for an approximate range between 50% to 70% of the OPEX in Rod Lifted systems. Industry has made significant improvements by separating the steel components during their relative movement by using different materials in between them and as sacrifice components. The rod guide is one of them and it comes today in several shapes and compositions. One of those compositions, and the most successful one, is the plastic guide. In the pursuit of the best plastic for West Texas wells, Oxy and Tenaris teamed up to assess Polyketone plastics with varied concentrations of glass fiber and seeking options to reduce the friction factors of this polymer on tubing ID. This paper describes the features in the selected polymer, the different configurations considered, an overall view to the qualification program, key quality assurance steps to comply with Tenaris QMS. Finally, Oxy’s implementation of the guides and the results from the operations. Since March 2020 Tenaris started supplying guides with this polymer to Oxy. To the date of this publication more than 50,000 guides have been installed with zero failures reported. 

Presented by:

Esteban Oliva and Jesus Abarca, Tenaris
Courtney Richardson, OXY

Artificial Lift Sucker Rod Pump
Room 110
(2022035) Using The Equilibrium Curve Concept to Determine the Most Efficient Gas Lift Injection Pressure and Rate for A Well
More Information

The capability of a gas lift system is heavily dependent upon the available gas lift injection pressure. Gas lifting a well from the deepest point of the formation results in higher drawdown pressure, more production with less lift gas, and less gas lift equipment yielding a more efficient system. However this cannot always be achieved because of limited injection pressure, limited gas injection rate and/or limitations of the gas lift equipment. In a gas lift project, what size compressor is needed to deliver the desired production? If a compressor is already in place, how deep can gas be injected and will it achieve the desired production? To answer these questions, an Equilibrium Curve can be developed. NODAL analysis and production information are necessary to build an Equilibrium Curve for a well. The outcome of this process is a plot of liquid production rate at various gas injection depths. This will provide the necessary information to size the compression needed to achieve the target liquid production rate and to determine the gas lift mandrel and valve design. Couple this curve with additional analysis will result in liquid production rates at various gas lift injection rates. Injection rate and pressure can then be used to determine compression horsepower required. The most efficient operation will be the gas injection pressure that yields the lowest compressor horsepower per barrel of liquid produced.

Presented by:

Robert Vincent, PL Tech LLC

Artificial Lift Gas Lift
Room 112
(2022015) High-Pressure-Gas-Lift: The Critical Variables Affecting Your Maximum Outflow Potential
More Information

Since its’ introduction to the unconventional oil and gas realm in 2018, Single Point High Pressure Gas Lift (referred to as HPGL going forward) has emerged as one of the top artificial lift choices for operators in the Permian and Anadarko basins. It has become a proven technology with over 1,250 applications to date as more operators are choosing it as their primary form of artificial lift for their unconventional assets. Its ability to achieve sustained high fluid rates as well as having a high sand and gas tolerance makes it the most versatile form of artificial lift offered in today’s market. HPGL is not a new concept having been discussed in SPE 14347. (Dickens, 1988) The concept was revitalized in SPE 187443 (Elmer, Elmer, & Harms, 2017) by which the authors of this paper emphasized its’ application for horizontal wells though at the time the needed compressor technology was not widely available to the market. This has changed as compression service companies have begun offering compressors designed to achieve the high discharge pressures needed to initially unload wells. This has led to a surge in HPGL applications as operators are looking to maintain the high output capabilities of ESPs with the benefits of gas lift. Gas lift is a naturally flowing process; therefore, it is important to understand the pressure drop across the entire system to achieve the desirable outcome. There are many components along the flow path from reservoir to sales that affect this pressure drop. HPGL has re-emphasized the importance of Nodal Analysis, and the understanding thereof, to production engineers. Proper design and installation of each node can drastically sway your well’s performance capabilities therefore proper modeling must be conducted to ensure the desired outcome is achieved. In this paper we will demonstrate the HPGL design method used today to ensure optimal output will be achieved. 

Presented by:

Victor Jordan, Estis Comprssion

Artificial Lift Gas Lift

Thursday, April 21st

08:00AM - 08:50AM (Thursday)

Room 101
(2022007) Decreasing Tubing Wear From Sucker Rod Coupling In Deviated Wells
More Information

In a reciprocating rod lift application, production tubing failure due to metal-to-metal contact with sucker rod couplings is a common problem in the highly deviated sections of the tubing string. The coupling is forced to be the point of contact against the tubing wall, which causes high friction and excessive tubing wear during the reciprocating motion. This excessive tubing wear typically leads to a hole in the tubing wall, resulting in high workover costs for the producer.  The coupling surface hardness, roughness, and coefficient of friction between the coupling and the tubing are all directly related to the resulting tubing wear generated at the contact region.  This paper intends to show through both in-house laboratory testing and preliminary field results that applying a lower friction coating to a sucker rod coupling decreases tubing wear and increases the life of the string. 

Presented by:

Justin Galle and Christopher Lauden
Weatherford 

Artificial Lift Sucker Rod Pump
Room 102
(2022039) Vulnerability of Remote Monitoring and Control Systems in the Oil and Gas Industries
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Vulnerability of remote monitoring and control systems in the Oil and Gas industries By George Tyson and David Allen, Oiltek Systems LLC The Modern oil and gas industry extensively uses systems to remotely monitor and control operations throughout the process. Supervisory control and data acquisition (SCADA) systems have had wide acceptance and used for years. Many SCADA systems use the Modbus protocol, developed in 1979, to communicate between the parts of the system. Most of these systems operate under MS Windows or DOS. This creates an environment of ever expanding vulnerabilities. Hackers have used these vulnerabilities to wipe out revenue and destroy infrastructure. In 2021 Colonial Pipeline Co. had their major East Coast pipeline shut down by hackers. Hackers also broke into the water system of Florida City and tried to pump in a "dangerous" amount of a chemical and was only stopped by an alert employee. In a similar incident, in 2015 hackers were able to flick digital switches in Ukrainian power substations, causing cuts affecting hundreds of thousands of people. These vulnerabilities are growing. Every time MS Windows is updated there is a chance of a new vulnerability to be introduced into the operating system or in third party software. The new system that is entering service in the industry is the Internet of Things (IoT) or the Industrial Internet of Things (IIOT). The very nature of these systems allow them to be secured far better than SCADA and other legacy systems. This paper will examine the structure of IoT and IIoT to show how it contributes itself to security.

Presented by:

David Allen and George Tyson
OilTek 

General Interest
Room 104
(2022006) Cloud Based Monitoring of Pumping Well Performance
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Data from fluid level, dynamometer, pressure, and motor power measurements were acquired by a standalone programmable monitoring system that uses internet and cellphone communication with the Cloud for remote monitoring of well performance. The system named Remote Asset Monitoring or RAM is described in detail in this paper that presents results from the tests that lasted several weeks, beginning with well pump down, just after new pump installation and continuing during normal production operation. The performance of the well was monitored in detail and additional measurements were acquired as needed based on the real time performance of the pumping system. 

In the past an operator was required to be at the wellsite to perform these tests. Once the portable RAM system was deployed at the well site and was programmed for standalone acquisition, the well performance trends were monitored wirelessly over extended periods of time without requiring an operator to return to the wellsite.

When connected via the cloud, the data acquisition schedule was adjusted remotely and the stored data was viewed and retrieved as needed. Additional measurements were performed and interpreted in real time so that the operator was able to troubleshoot and analyze the performance of the well from any location in the world.

Presented by:

Gustavo Fernandez, Dieter Becker, Ken Skinner and James N. McCoy
Echometer Company

Artificial Lift Sucker Rod Pump
Room 106
(2022021) Autonomous Control of Well Downtime to Optimize Production and Cycling in Sucker Rod Pump Artificially Lifted Wells
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For decades sucker rod pump artificially lifted wells have used devices called pump off controllers (POC) to match the pumping unit’s runtime to the available reservoir production by idling the well for a set time where variable frequencies drives are not available. In doing this the POC allows the well to enter a set period of downtime when the downhole pump fillage is incomplete to avoid premature failures, and then brings the well back online to operate before production is lost. Although this method has been successful for several years, autonomous control algorithms can be utilized to reduce failures or increase production in cases where the downtime is not already optimized. Optimizing the idle time for a sucker rod pump artificially lifted well involves understanding the amount of time required to fill the near wellbore storage area before generating a fluid column above the pump intake that will begin to hinder inflow from the reservoir into the wellbore. By varying the idle time and observing the impact on production and cycles the program hunts for the optimal idle time. By constantly hunting for the optimal idle time the optimization process can adjust the idle time when operating conditions change. This gives the advantage of always meeting the current well bore and reservoir conditions without having to have a user make these changes and determine what the downtime for the well is. Autonomously modulating the idle time for a well, if done properly will either reduces incomplete fillage pump strokes, in cases where the idle time is too short, or will increase the wells production in cases where the idle time is too long. Overall this will result in the optimization of wells by reducing failures and/or increasing production, generating a huge value to the end user by automating the entire process of downtime optimization.
 

Presented by:

Ian Nickell, ChampionX

Artificial Lift Sucker Rod Pump
Room 107
(2022001) Tubing Back Pressure on Rod Pump Wells
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One of the most misunderstood issues in sucker rod pumping is tubing back pressure. The great majority of wells that I have encountered in various fields have back pressure valves installed on the tubing side of a wellhead. However, a great many field personnel do not understand why back pressure is applied, how much to apply, and/or how it affects a well’s performance. This paper will discuss the why, when, and how tubing back pressure is applied along with some misunderstandings and issues of its application. 

Presented by:

Mike Brock, PLTech, LLC

Artificial Lift Sucker Rod Pump
Room 108
(2022004) Applying Data from Fluid Level Shots to Optimize Chemical Treatment Programs
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Data from fluid level shots can be very valuable in optimizing the chemical treatment program. For example, selecting continuous treatment vs truck treatment, adjusting flush volumes on truck treated wells, ensuring slip-streams are open and adequately slipping, or raising the SN depth on wells that cannot be pumped down. Just because chemical is being introduced into the backside does not mean it is effectively getting downhole, or getting downhole at all. This is especially true with flumping wells that are particularly hard to treat without a cap-string (although operators often apply cookie-cutter treatments for the whole field without taking individual well differences into account). Different methods of introducing chemical into the well and ways to overcome chemical treating challenges will be discussed and tied into how data from fluid level shots can help guide better decision making.

Presented by:

Shawn Dawsey, Downhole Diagnostic

Artificial Lift Sucker Rod Pump
Room 110
(2022016) Comparison Of Corrosion/Wear Resistant Barrel Coatings And Their Failure Behavior Under Acidic Conditions
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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 -or even improve when applicable. 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 market for different well conditions, including extreme well solids and H2S and CO2 service. These service conditions can be detrimental for pump performance if the right coating is not used. In addition to service conditions, well treatment methods such as acidizing can also deteriorate the coating performance, causing pump failures. This study focuses on the structure of 6 different standardized and specialty coatings on sucker rod pump barrels and an experimental study on their degradation in acidic environments, while familiarizing the reader with the recommended service conditions. 
 

Presented by:

Pinar Karpuz-Pickell and Levins Thompson
LUFKIN Don-Nan

Artificial Lift Sucker Rod Pump
Room 111
(2022010) New Mechanism of Sand Management Above ESPs
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Extending the run life of wells with Electrical Submersible Pumps (ESP) becomes a crucial need since it is one of the most economically expensive types of ALS. Following the need, a sand regulator has been designed to protect the pump during shutdowns, and it has been incorporated into traditional sand control configurations to offer extensive protection above and below the pump. This paper will explain the mechanism of the sand regulator as well as the benefit of installing this system alone above the pump or complemented with a sand control system below the pump. Since the wells had sand problem history and it was necessary to review pump designs, pulling reports, and sensor parameters along with well conditions such as production, tubing size, and particle size distribution were analyzed to build the best design for every single well. In the design, the geometry of the well was assessed to accommodate the cable and CT line downhole. The Acordionero Field is characterized by heavy oil production (400-1000 BFPD), with a viscosity of 430 cP @ 150°F, API between 13-15, low water cuts (Between 3.9% to 20%), and high fine sand production (3000 - 5000 ppm). Cohembí Field wells produce between 1000 - 6000 BFPD, with API between 17-18, high water cuts (> 77%), and a high sand production between 500 - 3000 ppm. The wells selected had other types of sand control and management systems and were highly affected by frequent shutdowns. The Sand Regulator design was installed on 20 wells and was compared with the performance achieved using traditional sand control solutions. After the installation, production has remained stable in all the wells applied, allowing to reduce the PIP of the well from 900 psi to 500 psi. Less current consumption has been observed after each shutdown in all the wells, extending the run life of some wells from 108 days to more than a year. Sensor parameters were analyzed after each pump restart to determine how difficult it was to restart operation after shutdowns. Compared to the tools installed above the ESP, this sand regulator allows flushing operation through it with flow ranges from 0.5 to 5 bpm. In addition, the unconventional design of this tool has opened the door to a new concept of ESP protection that works in wells with light or heavy oil and can be refurbished or inspected completely without cutting the tool.

Presented by:

Anderson Delgado, Jorge Espinosa, Gran Tierra; Luis Guanacas, 
Gustavo Gonzalez, and Carlos Portilla, 
Odessa Separator Inc.
 

Artificial Lift

09:00AM - 09:50AM (Thursday)

Room 101
(2022041) Value Of High-Resolution Data In Production Engineering
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Today, a good upstream or production engineer must understand the running condition of every well of which he is in charge in order to optimize production & profitability, usually by adjusting various setpoints. Typically, he will use data recorded by a pump-off controller (POC), fluid level shots, etc. as well as often coupling this wellhead-level data with intermittent information from stock tanks or test batteries.
To make things more complicated, most of the data generated by sensors on a field stays on the field controller’s local memory with just a select few data points actually transmitted (via low-bandwidth SCADA) to a host server and made readily accessible to engineers. Typically, this system is just capable enough to allow an engineer to diagnose crude issues and major failures. More modern systems send data to centralized control rooms far from the field, almost always unstandardized and unsanitized – as a result, more data sent means more man-hours needed to actually parse and analyze it which often falls by the wayside. In addition, it is often impractical to fully instrument a field with traditional automation solutions given the overwhelming infrastructure required and installation burden. As a consequence, most operators rely on incomplete data, leading to significant inefficiencies along with high operating costs.
In this presentation, we introduce state-of-the-art developments, both in terms of hardware technologies and mathematical data processing techniques used to automatically interpret data, as well as how these developments effectively leverage data points across the field to (1) reduce the cost of monitoring assets by an order of magnitude, making it affordable for lower flow legacy wells, (2) remove the need for routine in-person inspection of leases, and (3) increase production and equipment life-time while reducing power consumption through optimization.

Presented by:

Charles-Henri Clerget, and Sebastien Mannai
Acoustic Wells 

Prod. Handling
Room 102
(2022030) Unconventional Results with Conventional Long Stroke Rod Lift Systems: A Study of Design Process and Results Produced in Various Applications
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Sucker rod pumping is largely regarded as the final artificial lift method in a well’s lifecycle. Until now, the industry standard application of sucker rod pumping systems has been up to 400 barrels per day fluid production. With the industry advancing towards deeper wells and increasingly aggressive production targets, the challenge of meeting these application parameters while decreasing costs has become forefront to an operator’s requirements for profitability and in some cases, survival. To meet this need, Lufkin has established a system design comprised of a novel conventional 2560-500-320 pumping unit and fit-for-purpose rod string and pump, coupled with the ability to accurately control performance with automation. Through a comprehensive design analysis which factors in well characteristics, operational preferences, and production requirements, a system was developed to optimize production while minimizing lifting costs for operators. This approach has proven to lower or eliminate capital and operating costs for oil and gas producers by reducing the number or types of artificial lift methods, increasing fluid production, reducing failures, and lowering workover costs, as compared to other artificial lift methods or different pumping unit types. This paper will review design objectives, challenges, predictive analytics, implementation, economics, and the application results ranging from 400 to over 1000 barrels per day of fluid production achieved. 
 

Presented by:

Trey Binford and Lauren Silverman
Lufkin Industries

Artificial Lift Sucker Rod Pump
Room 103
(2022042) Leveraging Best Practices to Maximize the Value of Automation Systems and Optimization Software
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There are three components to a successful rod lift surveillance and analysis program. One, a rod pump off controller is needed to match inflow to outflow, reduce fluid pound when configured properly, and to shut the well down in the event of a downhole failure. Secondly, a host system is needed to provide immediate identification of downed wells, remote surveillance, and the ability to monitor and analyze hundreds of wells per day, enabling quicker identification of variances and solutions. And lastly, and of equal importance is to establish and implement business rules, work processes, and best practices that leverage the pump off controllers and host systems. In today’s world of ‘do more with less’, all three steps are needed to realize the full benefit of automation, and to achieve full optimization. Operators tend to spend the upfront dollars, which is by far the majority, for the hardware and software, but oftentimes never realize the full benefit due to not dedicating the resources, training the employees on technical Well Analysis, and implementing the supporting business rules, work processes, and best practices. The presentation will describe a situation in which a company utilized pump off controllers and a host system, but were lacking the business rules, work processes, and best practices to complement the hardware and software. The company leadership recognized gaps in skillsets, missed opportunities, and basic lack of understanding of the value of automation, and engaged ChampionX to do an assessment, or ‘health check’ of their fields and wells. A clear before and after picture of the metrics will be shown in the final paper. Below were the initial steps. 1. Both parties met to determine which metrics were to be measured, and acceptable targets/ranges. Below is a sampling of the individual metrics to be measured. a. Number of wells in some state of alarm. b. Wells cycling excessively. c. Wells with low volumetric efficiency due to over pumping or loss of displacement. d. Wells in need of additional lift capacity. e. Wells running with excessive SPM. 2. ChampionX Consultant mined, assembled, and presented the data to core team within said company. Each metric received a score. 3. Company Leadership presented findings and results to broader audience within Company operations. 4. The metrics and targets were adjusted where needed. 5. Workflows were built for each metric outlining the specific steps to take describing ‘how’ to improve the score. 6. Business rules were established for each metric describing ‘who’ and ‘when’ various steps are to be taken. 7. Each metric was assigned an ‘owner’. 8. The status of each metric is publicized daily via internal dashboard. With this exercise, it was immediately apparent to the company’s leadership team, and other personnel that the ROI on their automation system was significantly lacking. The presentation will show the value gained from implementing the third piece of the process. 

Presented by:

Brett Williams, ChampionX

Prod. Handling
Room 104
(2022032) Understanding Rod Loading
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Understanding rod loading is vital to reducing failure rates in reciprocating rod lift systems. By changing the minimum stress and using the modified stress analysis instead of the modified goodman diagram, manufacturers are “tricking” you into using high tensile strength and/or premium sucker rods in your rod designs. This presentation will attempt to explain rod loading why most rod lift applications do not require or need  high strength and/or premium sucker rods.

Presented by:

Russell Stevens and Gary Abdo

Lufkin Rod

Artificial Lift Sucker Rod Pump
Room 106
(2022029) A Review of Heat-Related ESP Studies
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Due to the ESP motor’s inefficiencies, heat is produced when converting power from electrical to shaft power. This generated heat is either transferred to the surroundings (i.e., through the producing fluids) or absorbed by the motor. In the absence of proper cooling, the motor temperature keeps increasing until either the motor fails or it reaches a temperature high enough to transfer the generated heat to its surroundings. According to the Arrhenius rule, equipment life is expected to reduce in half for every 18°C increase. Proper heat transfer not only avoids overheating failures but also improves the system’s reliability. A survey of the open literature was performed to evaluate how the industry approaches the heat transfer problem for ESP motors. The studies were divided into six different categories. A recurrent approach is to enhance temperature ratings of internal components in the motor and perform field trials to verify an increase in reliability. Although this is a sound practice from a commercial point of view, it does not provide any insight. This review recovers simple theoretical models enabling a more fundamental understanding of ESP motor heat transfer behavior in complex scenarios. It also elucidates areas where knowledge is still lacking, particularly in two-phase flow conditions around the motor.

Presented by:

Vinicius Kramer Scariot, Eduardo Pereyra, and Cem Sarica
The University of Tulsa 

Artificial Lift Electric Submersible Pump
Room 107
(2022028) Reducing Rod Pumps Stuck in Tubing in The Highway 80 Field
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Abstract In 2019, we presented the early results of a design change on our insert sucker rod pumps in the Highway 80 field. The information presented previously was eighteen months of data after this change was made. We also included over seven years of data prior to the change. Today we will discuss the forty-eight months of data collected after the design change and more than 11 years reviewing sucker rod pumps stuck in tubing in this field. When an insert rod pump gets stuck in tubing, increases in well-servicing events drive costs and safety risks. The Highway 80 area team reviewed the number of pumps stuck in tubing from 2010 to July 31, 2021. There was a total of 1,159 insert rod pumps that could not be pulled with the rods to retrieve the pumps. Pioneer Natural Resources previously chose to use a rubber fin element below the discharge of their insert sucker rod pumps to prevent lodging from occurring. With this change, there was a reduction in pumps stuck in the tubing, but approximately 10% of their pumps continued to get stuck. In 2017, Harbison-Fischer installed their brush sand shield on all of Pioneer’s insert pumps in the Highway 80 field and continues to do so today. This paper will discuss the results of forty-eight months since the first brush sand shields were installed. We will compare the pumps that were stuck in the tubing with and without the design change since the implementation. 

Presented by:

Rodney Sands, ChampionX
Rowland Ramos, Pioneer Natural Resources
Matt Roam, TWS Pump 

Artificial Lift Sucker Rod Pump
Room 108
(2022022) Collaboration In Developing a New Guide Material For West Texas Rod Lifted Wells
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Failures due to Rod wear and tubing wear account together for an approximate range between 50% to 70% of the OPEX in Rod Lifted systems. Industry has made significant improvements by separating the steel components during their relative movement by using different materials in between them and as sacrifice components. The rod guide is one of them and it comes today in several shapes and compositions. One of those compositions, and the most successful one, is the plastic guide. In the pursuit of the best plastic for West Texas wells, Oxy and Tenaris teamed up to assess Polyketone plastics with varied concentrations of glass fiber and seeking options to reduce the friction factors of this polymer on tubing ID. This paper describes the features in the selected polymer, the different configurations considered, an overall view to the qualification program, key quality assurance steps to comply with Tenaris QMS. Finally, Oxy’s implementation of the guides and the results from the operations. Since March 2020 Tenaris started supplying guides with this polymer to Oxy. To the date of this publication more than 50,000 guides have been installed with zero failures reported. 

Presented by:

Esteban Oliva and Jesus Abarca, Tenaris
Courtney Richardson, OXY

Artificial Lift Sucker Rod Pump
Room 110
(2022014) Management of Gas Slugging Along with Sand Handling to Improve ESP Performance and Efficiency
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A dual purpose design is presented in this paper to face high gas presence and sand production conditions in petroleum wells with an Electric Submersible Pump (ESP) system installed. The results of this design’s application in severely problematic wells, due to high gas and sand production, will confirm the importance of conditioning the fluid before it gets to the pump intake.

This engineered design consists of different stages from the isolation of the pump intake until the tubing bodies in charge of gas and sand handling. Engineering concepts were applied in the construction of this solution such as gas re-solubilization, changes of pressure and velocity, agitation, and vortex effect to finally present a design that is capable of breaking gas slugs into smaller gas bubbles that can be produced by the ESP system without impacting its performance, and at the same time separating fine solid particles (<250 microns) using centrifugal forces.

Case studies from wells located in the Permian basin will better explain the positive impact of selecting a proper downhole conditioning system to improve the ESP systems efficiency. A drastic improvement on the sensor parameters will also illustrate the effect of handling the gas and sand before the pump intake, which also leads to one of the most important consequences: A decrease in the number of shutdowns, which in turn decreases non-productive time, resulting in positive impact of fluid production. Additionally, the flexibility of this design is significant, since it allows it to be installed in a wide range of fluid production, gas-liquid ratio, tubing and casing sizes.

The novelty of this new design is the addition of the surge valve below the packer, which accomplishes multiple purposes: to avoid surging in the well, to allow testing the packer to assure it is properly set, and finally, allow chemical injection below the packer.
 

Presented by:

Neil Johnson Vazhappilly, and Gustavo Gonzalez, Odessa Separator, Inc. 
 

Artificial Lift Electric Submersible Pump
Room 111
(2022015) High-Pressure-Gas-Lift: The Critical Variables Affecting Your Maximum Outflow Potential
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Since its’ introduction to the unconventional oil and gas realm in 2018, Single Point High Pressure Gas Lift (referred to as HPGL going forward) has emerged as one of the top artificial lift choices for operators in the Permian and Anadarko basins. It has become a proven technology with over 1,250 applications to date as more operators are choosing it as their primary form of artificial lift for their unconventional assets. Its ability to achieve sustained high fluid rates as well as having a high sand and gas tolerance makes it the most versatile form of artificial lift offered in today’s market. HPGL is not a new concept having been discussed in SPE 14347. (Dickens, 1988) The concept was revitalized in SPE 187443 (Elmer, Elmer, & Harms, 2017) by which the authors of this paper emphasized its’ application for horizontal wells though at the time the needed compressor technology was not widely available to the market. This has changed as compression service companies have begun offering compressors designed to achieve the high discharge pressures needed to initially unload wells. This has led to a surge in HPGL applications as operators are looking to maintain the high output capabilities of ESPs with the benefits of gas lift. Gas lift is a naturally flowing process; therefore, it is important to understand the pressure drop across the entire system to achieve the desirable outcome. There are many components along the flow path from reservoir to sales that affect this pressure drop. HPGL has re-emphasized the importance of Nodal Analysis, and the understanding thereof, to production engineers. Proper design and installation of each node can drastically sway your well’s performance capabilities therefore proper modeling must be conducted to ensure the desired outcome is achieved. In this paper we will demonstrate the HPGL design method used today to ensure optimal output will be achieved. 

Presented by:

Victor Jordan, Estis Comprssion

Artificial Lift Gas Lift

10:00AM - 10:50AM (Thursday)

Room 101
(2022020) Artificial Intelligence and Automation for Surface Rod Lift Production
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Production performance monitoring has existed in Rod Lift Artificial Lift for decades, however there has lacked any action based on performance parameters. The Total Production Real Time (TPRT) Monitoring System incorporates data acquisition with artificial intelligence and automation to provide safer production operations for personnel and environment. TPRT collects live production data at surface on Rod BOPs, Stuffing Boxes, and Rod Rotators then drives actuation based on performance outside of expected performance parameters. For example, when a leak is detected at the primary seal for a Stuffing Box, TPRT engages a secondary actuator to recompress the seal, maintaining environmental control of the well during production as opposed to current product solutions which simply shut off the pumping unit at this minor inflection point on equipment performance. TPRT utilized point-to-point data acquisition and transmission to provide operators with live, cloud-based performance data on remote wells. The core functionality of TPRT is to maximize productivity while protecting from environmental leaks and limiting unnecessary visits to well sites.  
 

Presented by:

Joe Navar, Mesquite Technologies LLC

Artificial Lift Sucker Rod Pump
Room 102
(2022036) Continuous Rod Scanning Using LV-EMI™ Proprietary Technology
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Rod pumping unconventional wells is becoming increasingly challenging due to unpredictable downhole environments. Many unconventional wells exhibit significant deviation accompanied with corrosion making them difficult to rod lift without exposing downhole equipment to unpredictable damage mechanisms – specifically the rod string.

Continuous rod is a proven technology in these deviated unconventional wells as it increases the mean time between failures through lack of connections and distributed side loads. Although continuous rod will increase the mean time between failures, all rod pumping systems will eventually require an intervention. Traditionally, when continuous rod is pulled during a workover, inspections have been done visually in the field by experienced rig crews. However, this method is imprecise and subject to human error. This can result in unexpectedly early failure after a satisfactory inspection or additional cost from replacing mechanically serviceable continuous rod strings.

The Low Voltage – Electromagnetic Inspection (LV-EMI™) unit will detect three-dimensional discontinuities and cross-sectional loss in semi-elliptical and round continuous rod strings.  In this paper, the continued development of this new technology and the results from two semi-elliptical continuous rod string scans will be presented. Proposed future enhancements resulting from preliminary field tests will be identified.

Presented by:

Enio Oliveros, L.J. Guillotte Jr., Anne Marie Weaver, and Blake Vacek, LPS
Jared Jensen, Chevron

Artificial Lift
Room 103
(2022013) The Case Study of Applying Field Data By Utilizing Pressure And Temperature Survey Results And Winkler’s Valve Performance Analysis To Optimize Production In Gas Assisted Plunger Lift (GAPL)
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This case study has a completion with 2-7/8” tubing in 5-1/2” casing without a packer, with 8 IPO gas lift valves in conventional mandrels with an orifice as the last valve and a chemical screen below that. A grooved plunger was used in this well in combination with gas lift to reduce liquid fall back losses and provides a solid sealing interface between the liquid slug and the gas below it. The liquid rate declined drastically after operating the well on the gas lift at 600 MCFD rate and 1050 psig injection pressure for eight months. The well did not recover after trying several combinations of lift gas volume and plunger speed. As the lift depth in gas lift system depends upon the intersection point between surface injection pressure and multiphase flowing gradient. The pressure and temperature survey with resistance temperature detector (RTD) sensor has been run till the heal of the well at a stabilized injection gas flow rate along with wellhead recorders, recording casing and tubing pressures and temperatures for the entire duration of the survey. This process will help determine the lift point by identifying the Joules-Thompson cooling effect on the temperature curve. And it will also help sense the maximum and minimum pressures if the well is heading (surging or slugging) by keeping the wireline gauges at each depth for sufficient time. The methodical approach of creating a bridge between gas lift design and pressure-temperature survey interpretation gives operational insights into what was wrong with the gas lift operating envelope. The injection pressure endpoints are generated after performing a well-delivery analysis simulation with lower bottom hole pressure (revealed from the survey). And by utilizing Winkler’s gas passage analysis, the gas rate through designed port sizes in gas lift valves can be simulated, which is required for the existing deliverability of the well. Recent changes in operating conditions were proposed after performing several simulations on downhole flowing pressure and temperature at changing injection rates to measure the decrease in production. And applying these new conditions backed by the well’s data brought the well’s production back on the curve. This case history shows the complete scheme of creating an effective lift gas troubleshooting matrix in gas lift systems from concept initiation to execution and field installation. 
 

Presented by:

Haseeb Janjua, PROLIFTCO

Artificial Lift Gas Lift
Room 104
(2022005) Remote Monitoring of Pressure Transient Acoustic Tests
More Information

Data from acoustic fluid level and surface pressure measurements were acquired by a standalone programmable monitoring system that uses internet and cellphone communication with the Cloud for remote monitoring of pressure transient well performance. The system named Remote Asset Monitoring or RAM is described in detail in this paper that presents results from tests that lasted several weeks, beginning with well shut-in, continuing until pressure transient stabilization and afterwards during pump down until normal steady state production operation. The progress of the buildup test was monitored remotely by downloading the acquired data and reviewing the pressure trend with additional measurements acquired manually as needed. After buildup stabilization the pumping system was activated and during pump-down the fluid level, dynamometer, pressure, and motor power measurements were acquired automatically based on a user defined schedule. The combined results of the analysis were used to estimate reservoir performance and well productivity. In the past an operator was required to be at the wellsite to perform these tests. Once the portable RAM system was deployed at the well site and was programmed for standalone acquisition, the well performance trends were monitored wirelessly over extended periods of time without requiring an operator to return to the wellsite. When connected via the cloud, the data acquisition schedule was adjusted remotely and the stored data was viewed and retrieved as needed. Additional measurements were performed and interpreted in real time so that the operator was able to troubleshoot and analyze the performance of the well from any location in the world. 
 

Presented by:

Dieter Beck, Gustavo Fernandez, Ken Skinner, and Justin Bates
Echometer Company
A.L. Podio, Consultant

Artificial Lift Sucker Rod Pump
Room 106
(2022012) Evaluating the Use of Martensitic Steels for Sucker Rods
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The use of martensitic alloys in sucker rod applications has several significant advantages over ferritic-pearlitic alloys. Processing differences in making the different microstructures will be discussed, along with the resulting property and performance differences. An evaluation of the guidelines for optimal strength in various corrosive environments will be provided. Studies on the fatigue performance of martensitic and ferritic steels will be presented.
 

Presented by:

Joshua Jackson, US Corrosion Service

Artificial Lift Sucker Rod Pump
Room 107
(2022018) End-to-End Rod Control - Predictability in the Rod String
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Black Mamba Rod Lift’s helical centralizer stabilizes the rod string during pumping chaos. Chaos is understood as sucker rod buckling and negative loading (compression), which is impossible to eliminate in beam lift wells. The source of compression is often from nature (gas interference, fluid pound, gas pound) but can be operator induced (seating the pump, pump tagging), or compression as part of the pumping method and operation (pump friction, fluid load transition). When compression occurs on standard slick or guided sucker rod, rods experience bending moments, or focused points of high stress leading to micro-fractures which propagate and lead to rod parts. Multiple operators big and small have tested and validated Black Mamba’s system design. By April 2022, we will have had product tested and deployed for nearly 24 months. Operators elect to use Black Mamba for standard guide replacement, but most often opt for Complete, Predictable, End-to-End Rod Control (7 Black Mamba guides per rod), eliminating instability and providing a drastic increase in rod string reliability and rod string life, increasing MTF dramatically. The implementation of rod string stability is most often found at the bottom of the rod string where compression is most prevalent, working upward. Often 3/4" rods have been removed from system and string design due to their low AMOI and increased tendency for buckling. With constant centralization, 3/4" rods take compression and never buckle, following tubing exactly. Sinker Bar replacement is common in deviated horizontals, with the industry transitioning to guided 1” or 7/8” rod body with 3/4" pin connection (reduced coupling diameter allows for extended guide life). This product offering is provided to industry by multiple manufacturers, Black Mamba doing so in Permian, Bakken, Mid-Con. Utilizing 7/8” Slim Hole Couplings (with proper derating) is a good idea for extending rod guide life and extending the time-to-first-contact between coupling and tubing. 1” Slim Hole Couplings are so large they practically render rod guides useless for 1” rod body with 1” pin connection. We discourage the use of standard 1” pin connections when possible. Hybrid sucker rod products are available and actively promoted – 1” HA/HS rod with 7/8” connection reduces coupling diameter, maintains pin-connection strength, and will extend time-to-first-contact between coupling and tubing. Designing rod strings with chaos expected is an ideal method for ensuring the rod string is buckle-proof and ready for any source of chaos, operationally driven or nature driven. Compression Control Rod String Design considers all drivers of instability; the rod string can operate without bending moments, preventing a driving force of pre-mature sucker rod fatigue. Black Mamba’s installations have increased habitual failures by 6x (last 8 failures were at 3 months each), allows operators to pump 192” stroke units at 10 SPM reliably, and removes all guess-work out of string design. Product will have been deployed for nearly 2 years across the world in a variety of pumping conditions. 

Presented by:

Jonathan Martin, Black Mamba Rod Lift 
 

Artificial Lift Sucker Rod Pump
Room 108
(2022002) Optimizing Rod Lift Operations with Edge Computing
More Information

Modern sucker rod pump operations rely on pump-off controller’s, surveillance dashboards, and human intervention to maximize production and pump performance. As a result, rod pump operations often suffer from high manual workload, limited diagnostics and dynamic well conditions. For wells fitted with pump-off controllers and variable speed drives, challenges remain around data gathering and evaluation. Bringing well specific insights to action requires continuous physical supervision to ensure well uptime. Edge computing and Internet of things (IoT) technologies offer high frequency data gathering, real-time evaluation and a reliable mechanism to maximize rod pump productivity while automating redundant tasks. Advanced computations, enabled by edge computing, allow for a more comprehensive analysis of pump conditions that compliments and surpasses the capabilities of pump off controller automation. This paper will demonstrate how closed loop algorithms deployed on edge computers work to ensure the best operating conditions, autonomous dynacard evaluation and interventions, and a proactive approach to help manage anomalous, high failure wells. 

Presented by:

Jared Bruns and Abhishek Sharma, Schlumberger 
Will Whitley, Oasis Petroleum 

Artificial Lift Sucker Rod Pump
Room 110
(2022025) A New Approach to Safely Locking Out Pumping Units Using a Hydraulic Sheave Lock Versus Traditional Methods
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This presentation will discuss a new method of locking out beam pumping unit using a patented and engineered hydraulic sheave lock to support reducing risk at the well site when the pumping unit is shut down for routine maintenance or workovers. It will explore merits of keeping workers entirely out of the swing zone, allowing personnel to accomplish tasks safely and easily, without risk of brake cable failure or slippage resulting in movement of the counterweights. The discussion will focus on how this approach impacts traditional operational practices including an analysis of key metrics encompassing the ability to reduce third party service costs, avoid near miss and serious safety incidents, while also reducing traffic at the well site, resulting in less road damage and carbon emissions. Discussion will focus on how this new process adds value by reducing costs and improving safety for producers. 
 

Presented by:

Tracie Reed, Silverstream Energy Solutions Inc. 
Don Foley, and Kurt Richard, KUDO Energy Services 

Artificial Lift Sucker Rod Pump
Room 111
(2022019) Jet Lift Bridges Transition Gaps Between Various Forms of Artificial Lift in Horizontal Well Lifecycle
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The objective of this paper is to share insights from a case history of jet lift applications in the Permian Yeso play. Apache Corporation was among the first operators to deploy horizontal drilling and multistage fracturing in the Yeso formation in Eddy County, N.M., targeting dolostone/limestone/sandstone reservoirs interbedded with shale and anhydrite. The Yeso yields oil and liquids-rich gas at depths averaging 5,000-6,000 feet. Apache’s initial strategy was to commence post-flowback production from fractured wells with electrical submersible pumps, and then transition to rod lift as rates declined over time. However, as the wells approached the transition window between ESPs and rod pumps, high sand content and gas-to-liquids ratios caused frequent downtime for both types of lift, negatively impacting well performance. To counter these problems and accommodate the solids and GORs, the operator installed concentric string jet lift. This solution effectively bridged the application gap between high-rate ESPs in early well life and lower-rate rod pumps later in the lifecycle. Referencing the well data, the results section summarizes how jet lift operations successfully handled variable flow rates with high GORs / solids while achieving targeted drawdown and production output. The results demonstrate that jet lift improved uptime, maintained expected production decline, and reduced cost by eliminating frequent workovers to repair rod pump components. The novelty of this approach is the extended application range for jet lift, emphasizing its inherent flexibility in transitioning to different forms of artificial lift to meet changing production profiles as horizontal wells progress through their characteristic steep decline curves when faced with a deviated well that will increase rod-on-tubing failures and premature wear of the pump. The discussion synopsizes jet lift’s applicability across the lifecycle in horizontal resource plays, and the problem-solving benefits of concentric tubing string designs. The paper concludes with an assessment of jet lift’s evolving capabilities; specifically, how advancements in downhole sensors, remote monitoring / automation, and digital optimization are capturing value and enabling operators to deploy jet lift as an alternate lift system. 
 

Presented by:

John Massey, ChampionX 
 

Artificial Lift

11:00AM - 11:50AM (Thursday)

Room 101
(2022024) Field Trial Data Demonstrates Benefits of Advanced Metallic Coating that Actively Protects Rod Strings against Corrosion in Challenging Well Environments
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The objective of this paper is to share insights on mitigating sucker rod corrosion damage in vertical, horizontal and deviated wells with aggressive corrosive conditions such as H2S and CO2, particularly those with histories of corrosion-related rod/tubing failures.

Corrosion is a common problem in production operations, accounting for two-thirds of all rod string failures and costing billions annually to remediate, according to NACE International. This paper presents the development and initial field application results of a continuously applied metallic coating that actively participates in the electrochemical aspects of corrosion in carbon and low-alloy steels. Moreover, the solution protects uncoated segments of rod and other steel components in the wellbore while reducing abrasion by enhancing friction properties compared to bare steel.

The authors outline the key properties and characteristics of this coating, including evaluating its performance relative traditional corrosion protection measures such as barrier coatings. Rather than acting as a barrier layer, the metallic coating actively protects against corrosion and has inherent chemical properties that self-heal surface scratches and abrasions. This is particularly valuable in horizontal and directional wells with high dog leg severities and sideloading forces that contribute to rod/tubing abrasion.

Results are presented from laboratory testing as well as initial trial applications in wells with histories of rod failures due to corrosion, typically requiring interventions with workover rigs. In one such trial, the metallic coating was applied to a coiled rod string installed in a high-CO2 content well on progressing cavity pump. The coated coiled rod string was installed in January 2019. Ater five months of service, the coated string was pulled to inspect its condition. The examination revealed that the rod was unaffected by corrosion. A second inspection after nine months found evidence of rod string wear but no corrosion damage. The well has been in continuous operation for 35 months (and counting), more than doubling the average run time before installing coated coiled rod.

The novelty of this approach is the application of an advanced materials science coating to extend rod string service life in corrosive environments through active protection. In addition, it requires no special handling or installation equipment, and the metallic material allows rod strings to be recycled (eliminating potential environmental and downstream damage risks associated with barrier coatings).

As supported by lab and field case study data, the results of deploying this method include increased production uptime, reduced workover frequencies and associated remediation costs, and lower overall LOE and lifting cost per barrel of oil produced. 
 

Presented by:

Alex Perri and Angela Sultanian

ChampionX, Pro-Rod Coiled Rod Solutions

Artificial Lift Sucker Rod Pump
Room 102
(2022033) Plunger Assisted Gas Lift (PAGL) in the Permian Basin
More Information

Plunger Assisted Gas Lift (PAGL) in the Permian Basin Over the last few years Gas Lift has become a popular artificial lift choice for producing unconventional wells in the Permian Basin. Gas Lift is a good choice for producing wells with high bottom-hole pressures (BHP) and high gas liquid ratios (GLR). Gas Lift is also a good choice for wells that produce solids or have deviated wellbores. Gas Lift however like all artificial lift choices has an optimum range which typically tends to be above five hundred barrels per day. When Gas Lift gets below five hundred barrels per day inefficiencies begin to surface with regards to the amount of fluid produced relative to the amount of gas injected. These inefficiencies can be addressed by running a hybrid system of gas lift and plunger lift to help maximize fluid production and minimize injection gas with the use of an interfacing tool known as a plunger that free cycles up and down the tubing and keeps gas from breaking thru fluid while flowing to surface. The system known as Plunger Assisted Gas Lift (PAGL) is becoming more popular and some operators have gone almost exclusively to this choice as Gas Lift wells begin to mature. This paper will highlight operators in the Permian Basin who have successfully integrated these systems into their long term production plans and review before and after production numbers, costs and estimated annual savings and increases to net revenue. The mechanical aspects of the system will be reviewed as well as installation and best operating practices. Additionally a preview of producing the well intermittently as it continues to decline by another hybrid system known as Gas Assisted Plunger Lift (GAPL) will be reviewed. 
 

Presented by:

Mike Swihart, PROLIFTCO

Artificial Lift Gas Lift Plunger Lift
Room 104
(2022034) Wireless Sensor Technology to Monitor Rod Rotator Performance
More Information

Mechanical rod rotators have been used as part of the beam lift artificial lift system since the concept was first patented in the late 1930’s. By rotating the rods, the frictional wear surface can be distributed around the circumference of the rod, versus on a single side of the rod. By distributing the wear surface, the rod life will be significantly extended. In the same way, the industry has used tubing rotators to derive this same benefit on the tubing, distributing the wear around the inner circumference of the tubing. One of the biggest challenges associated with operating rotators is being able to confirm that proper rotation of the rods is taking place. The speed of rotation is very slow and is not easily observable without carefully watching the rods for several strokes, and often requires an observer to be very close to the rod string. Because of this challenge, the failure of a rotator can go undetected for long periods of time, which often results in premature failure of the rod system. This paper will explore some of the methods that have been used to monitor rod rotators, including some of the advantages and disadvantages of these methods. It will also introduce a new wireless sensor that is capable of remotely reporting not only the proper operation of a rotator, but also the actual speed of rotation, which is very useful to understand the rotator’s performance and to detect progressive failure. Field trial data was gathered as the algorithms were improved to eventually yield accurate monitoring capabilities. This data will be presented, along with several conclusions. This innovative sensor is adaptable to existing rotators, and can be easily integrated into existing pump-off controllers, so it is agnostic with respect to the manufacturer of the equipment and will have broad application for rod pump wells in the industry.
 

Presented by:

Terry Treiberg, Theta Oilfield Services-ChampionX
Justin Conyers, California Resources Corp. 

Artificial Lift Sucker Rod Pump
Room 106
(2022017) Downhole Sucker Rod Sensor – Mystery Solved
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With the increase in the number of horizontal wells drilled in the past 15 years, the technology for predicting downhole conditions and troubleshooting problem wells has not kept up with the increased complexity of these deeper and deviated wellbores. The systems in use are no longer accurate or sensitive enough to determine what is causing the problem(s) resulting in shorter meantime between failure and higher workover cost to the operators. To unravel the mystery we introduce the Downhole Sucker Rod Sensor which measures what is happening downhole and enables the customer a systematic approach to troubleshooting and therefore reducing the number of failures while providing a method for measuring the effectiveness of new and existing technologies. These sensors can be strategically placed anywhere in the rodstring and collect high-resolution measured data for pressure, temperature, torque, compression, velocity and position. In addition to generating a high resolution measured downhole DynaCard that can distinguish sync issues with different strokes per minute (SPM). The data is used to uncover issues with string wear i.e. alignment or sync issues, friction, pump and tubing issues as well as calculated values for specific gravity, pump fillage, and pump intake pressure. The main objectives are summarized as follows: o Comparing actual Downhole DynaCard measurements to the Surface and the Predicted Cards o Maximizing reservoir drainage and production optimization o Identifying, isolating and optimizing mechanical issues in problem wells o Measuring the impact of new and existing technologies (such as guides, friction reducers, …) and their effectiveness in extending the service life of the SR system. o Verify if rod guides, friction reducers… are adding value and not just cost! Vision: o Utilize sucker rod sensor(s) on problem wells and convey lessons learned to other wells. o Improve the software systems currently calculating downhole dynagraphs. o Improve the accuracy of (surface) software calculations which will yield improvements for a large number of unconventional wells. o Provide our Customer’s with a competitive advantage. 
 

Presented by:

John MacKay, Stian Slotterøy, Rutger Suermondt, Paolo Santos - Well Innovation 
Keith Fangmeier, Cedar Ranch Consulting 

Artificial Lift Sucker Rod Pump
Room 107
(2022027) NON-CABLE Actuated Rod Rotator: Technology Development and Field Experiences
More Information

The use of rod rotators is key to extend the life of sucker rod string couplings in all intentionally and not intentionally deviated wells. Its applicability has proved to be a low-cost solution, giving an even wear on sucker rod couplings, extending considerably their run time.
One of the major issues with conventional cable actuated rod rotators is the integrity of the cable, its installation and proper maintenance. It’s common to heard from operators losing the cable connection and ending up on a premature failure on sucker rod couplings due to localized wear.


Initially designed as a solution for long stroke belt driven units, where cable rod rotators weren’t reliable, a telescopic arm actuated rod rotator solves the issue with minimal down time. This innovation then was implemented in conventional pumping unit setups providing reliable rotations of sucker rod strings.


This paper describes the development process for the telescopic arm actuated rod rotator and the case studies in their initial set of applications in operation.
 

Presented by:

Nicolas Guyubas, Martin Ruiz Palero, Daltec Oil Tools
Rodrigo Ruiz, Duxaoil Texas LLC

Artificial Lift Sucker Rod Pump
Room 108
(2022035) Using The Equilibrium Curve Concept to Determine the Most Efficient Gas Lift Injection Pressure and Rate for A Well
More Information

The capability of a gas lift system is heavily dependent upon the available gas lift injection pressure. Gas lifting a well from the deepest point of the formation results in higher drawdown pressure, more production with less lift gas, and less gas lift equipment yielding a more efficient system. However this cannot always be achieved because of limited injection pressure, limited gas injection rate and/or limitations of the gas lift equipment. In a gas lift project, what size compressor is needed to deliver the desired production? If a compressor is already in place, how deep can gas be injected and will it achieve the desired production? To answer these questions, an Equilibrium Curve can be developed. NODAL analysis and production information are necessary to build an Equilibrium Curve for a well. The outcome of this process is a plot of liquid production rate at various gas injection depths. This will provide the necessary information to size the compression needed to achieve the target liquid production rate and to determine the gas lift mandrel and valve design. Couple this curve with additional analysis will result in liquid production rates at various gas lift injection rates. Injection rate and pressure can then be used to determine compression horsepower required. The most efficient operation will be the gas injection pressure that yields the lowest compressor horsepower per barrel of liquid produced.

Presented by:

Robert Vincent, PL Tech LLC

Artificial Lift Gas Lift
Room 110
(2022003) Impact from Analyzing The Run Life Statistics Using Survivability Curves Methodology On ESP Key Performance Indicators
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Managing extensive Electrical Submersible Pump (ESP) operations and evaluating their performance can be a challenging task, especially in unconventional reservoirs. Varied operational environments, expansive geographical areas, large ESP populations, different declination patterns, diverse fluid properties and well designs and different service providers are some of the complications that operators face every day. Many companies measure the success of any artificial lift project focus on simple run life statistics as the central key performance indicator; however, these types of statistics may not always be enough in providing significant information to decision makers. It is vital to the success of any project to establish a performance evaluation structure that can effectively capture deficiencies and highlight potential improvements. Survivability curves are the result of the statistical model based on Kaplan-Meier analysis, which was originally created to measure the fraction of subjects living for a certain amount of time after treatment in clinical trials, so similar methodology was deployed to analyze an important dataset of ESPs to deeper understand by factoring and comparing elements which influence ESP run life, showing results that are easier to understand and represent real value to operators on several areas as safety, engineering, reliability and operations. As a result, from this comprehensive study jointly initiated between an oil operator and ESP vendor, corrective actions were taken that drive improvements in all ESP aspects, which can be seen not only in today’s KPIs, also influence future artificial lift projects. Being able to draw conclusions about the expect runtime can be used to drawn insight on find areas where efforts should be focused to improve ESP reliability, find where ESPs can be best utilized to improve field performance, and identify opportunities to reduce workover cost. Similar analysis can be done to visualize ESP runlife improvement over time, compare different ESP technologies, and find expected runtimes by completion design or producing formation. The values of insights gained from statistical analysis can be gotten from any field of ESPs to aid in making better oilfield business decisions.

Presented by:

Christopher Bryan and Miguel Irausquin
Baker Hughes

Artificial Lift Electric Submersible Pump
Room 111
(2022023) The Silver Bullet: Overcoming Gas Interference In Unconventional Rod Pumped Wells
More Information

With today’s highly dynamic unconventional wells, gas separation is essential after the conversion from electric submersible pumps (ESPs) to rod lift. Unconventional wells in the Permian Basin have high initial rates with steep declines rates, which result in a high gas-to-liquid ratio very early in the life of the well. As the reservoir pressure draws down below bubble point pressure, increasing volumes of free gas begin to break out of solution. This results in downtime due to erroneous attribution of well condition to pumped off in a critical time when aggressive fluid extraction is needed. Better well optimization is achievable through proper gas separation to maximize production and minimize downtime. Common solutions to this problem involve the use of Mother-Hubbard or packer style separator, which are not always adequate for the task and can be easily overrun by gas. Additionally, if the well is pumped too aggressively, the gas separators can be overrun by production, meaning minimal gas separation occurs. Combining the efficiency of the industry’s leading packer style gas separator, a patented shroud and the new innovative technology of the bypass tubes from the ESP Gas ByPass, the Silver Bullet maximizes gas separation using two pathways for gas separation to occur. Using the Silver Bullet increases total production by both ensuring that the pump is full and by reducing the amount of time the well spends idle. Furthermore, decreasing the number of gas interference events helps reduce failure and increase the life of downhole equipment. Less gas interference in the pump leads to longer run times, more consistent pump fillage and ultimately more revenue. This paper details the technology behind the Silver Bullet and presents case studies proving tool efficiency. 
 

Presented by:

Russell Messer and Matt Raglin
WellWorx Energy Solutions

Artificial Lift Sucker Rod Pump

12:00PM - 01:15PM (Thursday)

Room 101
(2022031) Cost-Effective Solution to Corrosion-Induced Rod Failures
More Information

When rod pump wells are operated in corrosive environments, corrosion induced sucker rod parts can lead to premature well failure and expensive, repeat workovers. Many corrosion mitigation solutions exist to combat this type of failure, including metallurgy, chemical inhibitor, and epoxy coatings, but they can be costly and not all solutions are appropriate for all types of wells.

In deep wells that require higher tensile rod strength, corrosion friendly metallurgy is generally not an option. In low producing wells, epoxy coatings may not be economically justifiable, depending on lead times and distance from a coating plant. Corrosion inhibitor can require constant monitoring to ensure the treatment is working and not all wells have an environment that promotes an even coating of inhibitor. 

In wells where traditional mitigation techniques have not been effective or economic, RodGuard has been successfully used to reduce the frequency of corrosion-induced rod parts. 
 

Presented by:

Kara Walling, NOV Inc. 

Artificial Lift Sucker Rod Pump
Room 102
(2022038) Downhole Sensors Support Successful Drilling Redesign Initiative in the Midland Basin
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The Midland Basin teaches a hard lesson in drilling harder rock. SM Energy first drilled there in 2008 before launching a successful horizontal drilling campaign in 2013. This work focuses on a successful application of the limiter redesign process supported with downhole sensors. Whirl suppression generates ROP performance improvements. This objective is complicated with a coupling to stick slip in hard rock applications. High WOB and therefore high torque tends to excite stick slip. Torque oscillations start, speed oscillations follow, and result in inconsistent DOC. Bit forensics on large wear flat shoulder cutter wear and delamination indicate high speed, friction, and heat damage under these conditions. This problem is explored in depth across the interbedded intermediate section of three pilot wells within the operator’s southern Midland Basin acreage. All three wells were drilled in a single bit run to TD and successfully cased and cemented by design. Three high frequency sensors recording at 100 Hz were installed in each BHA – one located in the bit, above the drilling motor, and at the drill collars. High frequency surface measurements were successfully tied to subsurface sensor observations. Good wellbore trajectory design, high ROP, and low planned dog leg severity positively contributed to weight transfer exceeding +97% based on WOB measurements in the BHA. Autodriller setpoint control and tuning unlocked ROP gains between 20-40% in the shallow hole section. MSE is reintroduced. Its practical value in baseline drilling surveillance and benchmarking is confirmed. The first well is treated as the control in the project. The trial starts with the common bit and BHA for the area with planned parameter step tests performed in each significant formation group. The second and third wells repeat the same workflow with progressive BHA changes to a single component. Depth of cut control is designed and utilized successfully on these wells to reduce torque oscillation. Roller reamers implemented on the final well act as a low torque stabilizer to increase useful torque at the bit. Torque stabilization and minimizations strategies must be paired with sufficient drill string stiffness to maximize performance impact in high WOB applications. The drilling performance initiative outlined in this paper is meant to be accessible to all drill teams and a call to action to redesign problems to the economic limit, forever. 
 

Presented by:

Ritthy Son, SM Energy

Drilling Operations
Room 104
(2022037) The Downstroke Pump and Special or Unusual Sucker Rod Pumps Explained
More Information

The Downstroke Pump and Special or Unusual Sucker Rod Pumps Explained This paper will explain the author’s theory of operation of the pump that lifts fluid on the downstroke, using the weight of the rods, and its loading of the sucker rod string and pumping unit. Other special sucker rod pumps will be likewise explained, using the author’s understanding, including the family of double displacement type pumps, compound compression ratio pumps, traveling barrel pumps, and others. Also discussed will be the loading changes incurred when some of these pumps are configured in the top hold down, bottom hold down or tubing pump configurations. 
 

Presented by:

Benny Williams, Q2 Artificial Lift Services

Artificial Lift Sucker Rod Pump
Room 107
(2022026) Troubleshoot Oil and Gas Wells Using Acoustic Level Shots
More Information

Shooting fluid levels has become a well-known practice in support of daily production operations. The practice of shooting fluid levels is so well-known, in fact, that the term, “shooting fluid levels” is assumed to mean checking the fluid level to determine if a well is producing the maximum fluid potentially available from the formation. The most common use of an acoustic liquid level instrument is to measure the distance to the liquid level in the casing annulus of a well having a downhole pump. Shooting fluid levels inside the tubing (instead of just inside the casing annulus) is common practice in flowing gas wells. Fluid level both inside the tubing and inside the casing annulus is a valuable trouble-shooting technique used on wells that have either stopped producing altogether, or production rate has drastically decreased. Analysis of acquired fluid level shots can determine if there is a hole in the tubing. Tubing shots acquired at uniform time intervals can show ineffective pump operation, where down hole liquid level rise in the tubing occurs too slowly. Fluid levels shots are effective tools when troubleshooting oil and gas wells. Many fluid level examples will be presented that discuss how tubing and casing shots are acquired and analyzed to determine hole-in-tubing on all types of oil and gas wells. 
 

Presented by:

Lynn Rowlan and Gustavo Fernandez
Echometer Company

Artificial Lift Gas Lift
Room 108
(2022040) Autonomous Chemical Optimization and Remote Monitoring: A Case Study
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With the development of new digital technology over the last several years, our industry has seen many benefits of remote monitoring and automation in sectors within drilling, completion, and production. One area that has lagged is remote monitoring and automation of production chemicals applications. This paper will review initial pilot testing of automated chemical pumps on a group of newly completed wells. The initial objectives of this pilot test were to 1) seek to identify potential chemical cost savings during the early life of the well by autonomously linking chemical injection rates to production volumes; 2) confirm that chemicals are being consistently applied at the prescribed dosages; 3) set up notifications alerting personnel of potential problems, such as low tank volume or inadequate power supply; 4) be able to use the historical chemical tank level data to assist in approval of chemical delivery invoices; 5) determine if operational efficiency of chemical vendor can be improved by needing to check tank volumes and pump rates less frequently; 6) help identify other applications in which this technology could be beneficial such as saltwater disposal chemicals or methanol injection for compressors. Methods, Procedures, Process: Automated chemical pump controllers with built-in communication devices are used to monitor and optimize chemical injection rates. The chemical pump controllers are then able to be remotely monitored and controlled using optimization software. A prescribed dosage target of chemical to production volume is assigned in the software where the software then calculates dosing rate each time a new well test is entered. The software sends the new dosing rate to the chemical controller. We also configured the software to send automated emails to the Well Optimization Analysts and the chemical vendor representatives to alert personnel of low tank volumes or low voltage issues. Results, Observations, Conclusions: The supply voltage would drop so low during the night that the pump would stop pumping. We had to upgrade our solar power system on certain wells to provide enough power to consistently achieve target chemical injection volumes. We then set up low voltage alarms so that we are immediately notified if there is a problem with the system. Also, by remotely monitoring tank levels and alarming on low tank levels we ensure that chemical deliveries are made on time. Another benefit from monitoring and trending tank levels is the ability to use the historical data to assist in confirming chemical invoices. Novel/Additive Information: Chemical programs have historically been controlled manually by a chemical vendor technician or operator on location in a reactive manner. Chemical tanks running dry, the loss of power, and lack of accountability can all be mitigated and resolved by automating chemical injection and enabling remote control. 
 

Presented by:

Dylan Bucanek, ChampionX
Jeff Clack, ConocoPhillips 

Prod. Handling
Room 110
(2022011) Cenesis Phase System for High Gas ESP Applications
More Information

Electric Submersible Pumps (ESPs) are severely affected by free gas entering the pump, which cause significant degradation in pump performance, due to gas locking conditions cause by bubbles blocking the fluid from passing through the impellers, resulting in frequent shutdowns and restarts, which increase the risk of early failure. This effect is even worst when a gas slug event, very common in horizontal wells drilled in unconventional reservoirs, hit the system, this event consist of a large volume of light density fluid (gas) flowing through the system, overheating the motor and pumps due to a no liquid flow condition, resulting in unstable production due to ESP shutdowns caused by underload or high motor temperature. The industry has used shrouds, rotary and vortex gas separators, and more recently, multiphase pumps to handle the gas, however, there are some applications where this equipment is not enough to handle the Gas Liquid Ratio (GLR). Recently two Oil Operator Companies in the Permian basin following our recommendation successfully installed a multiphase encapsulated production solution technology to separate the gas from the liquid in the wellbore. As produced fluids, pass the pump at high velocity, the heavier liquid falls back into the shroud in a low-velocity area between the tubing and the top of the shroud, allowing the gas to continue to the surface. This system has proven to separate the gas from the liquid effectively (> 90% of efficiency), stabilizing operations within a certain operating window. In this document, results are shown for two successful field cases, how uptime improved, being able to reduce the number of shutdowns, improving operational performance and increase the drawdown maintaining stable production of the wells. 
 

Presented by:

Miguel Irausquin, Mohammad Masadeh,  Nelson Ruiz and Oswaldo Robles
Baker Hughes 

Artificial Lift Electric Submersible Pump
Room 111
(2022009) A Revolutionary Packer Type Gas Separator That Involves G-Force to Exceed Traditional Gas Separation Efficiency In Oil And Gas Wells
More Information

A revolutionary packer-type gas separator was designed to improve gas separation efficiency downhole. A deep analysis of gas separation methods was done to better understand the nature of the process and to design a tool that could generate enhanced conditions for the gas separation phenomenon. During the research stages where data from Permian fields were analyzed to develop this new design of gas separator, the engineering team found three main challenges in downhole gas separation. The first one was the wells were being converted from ESP to rod pump earlier, forcing the downhole gas separators to handle more production than before. The second is the small production casing size that usually is 5.5” casing, which significantly reduces the annulus area that is vital to get an effective gas separation efficiency, and finally, the gas slugging behavior, which in high proportion can lead to a gas lock-in sucker rod pump systems. Following the requirements and limitations, a packer-type gas separator was designed, built, and tested in oil wells. This gas separator has an outlet section of 1.89” OD, which means the design maximizes the gas separation area where it really matters at the fluid outlet point. The innovative fluid exit slots design creates a linear flow path allowing gas to separate and flow upward the casing annulus in a natural way. Additionally, a valve below the cup packer was included to eliminate surging in wells. This valve prevents surging by holding the fluid in the vertical section, thus avoiding backflow when the gas slug leaves liquids behind. To evaluate the new design, a calculator was developed to estimate the gas separation efficiency downhole and compare the gas separation efficiency among different gas separators. After the implementation of this design in 5 wells, the results confirmed the high gas separation efficiency obtained with this new gas separator configuration. The novelty of this gas separator design is the outlet section that takes advantage of the gravity force to increase the gas separation efficiency without limiting the tensile strength of the BHA. Also, the fact of including a valve to address the surging condition in the well before the fluids go through the gas separation is a new approach in a gas separation tool. 

Presented by:

Lee Weatherford, Gustavo Gonzalez, Luis Guanacas, and Donovan Sanchez
Odessa Separator
Michael Conley, Steward Energy

Artificial Lift Sucker Rod Pump

Annual Conference Info

NEXT CONFERENCE: APRIL 18-21, 2022