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. 
 

There are many potential failures in production wells which result from corrosive downhole environments, mechanical aspects of artificial lift or a combination thereof. Tubing failures constitute a costly failure mechanism in production wells. Tubing inspections can provide valuable insight on the condition of tubing as well as the distinction between causes of tubing degradation. This information is utilized to replace worn and pitted tubing joints, failure root cause analysis and implement solutions to mitigate future failures. Due to the high cost of a tubing failure, a high-quality tubing inspection is critical to identify potential failure mechanisms in a used tubing string. This paper serves to discuss the engineering and economic benefits of a tubing scanning program. The results of an in-plant inspection compared to an EMI wellhead inspection on two Anadarko wells in the Permian Basin exemplifies said benefits. This paper provides an in depth analysis of tubing inspection technology, the pros and cons of both wellhead and in-plant inspections and data utilization to reduce downhole failures.

High gas-liquid formation ratios appear as the fluid level decreases and as a result significant decreases in pumping efficiency are seen in the ESPs. This problem force frequent shutdowns in the pump because the gas is incapable of adequately cooling the motor and this forces the companies to maintain high fluid levels to avoid the formation of free gas at the pump intake, which increases the PIP and limits the production of fluid. A new and innovative downhole gas separator has been introduced in recent applications to treat gas slug’s problems. For these applications, a shrouded ESP with a double stage of gas separation connected to the bottom of the shroud as an intake was designed to break and separate gas slugs and avoid gas entrance into ESPs by forcing free gas to go around the shroud and produce through the casing. The gas separator uses an innovative design to break the gas slugs in the annular section between the casing and the tool, additional with the internal dual flow system the separation efficiency increases while it’s created a chamber lift filled with free gas liquid.  

With this new system, the fluid is now forced to pass through an additional gas separator which helps to separate gas and keeps lower PIP than usually promoting the fluid production in the wells.
 

When an insert rod pump gets stuck in tubing there will be a significant increase in well-servicing events. These events cost the consumer money and also places the worker's safety at risk. 

The Highway 80 area reviewed the number of stuck rod pumps in tubing conditions that had occurred from 2010 to mid-2017.  In total, there were 825 pumps that were unable to be pulled with rods, which resulted in tubing being pulled to retrieve the pump. To try and resolve this issue Pioneer used a rubber fin element below the discharge of their insert rod pumps. By doing so they saw a reduction in stuck pumps with the rubber element. Even though this method decreased the number of stuck pumps, about 10% of their pumps continued to get lodged in the tubing. 

In the third quarter of 2017, Harbison-Fischer implemented a design change to these wells. The Harbison-Fischer Brush Sand Shields were installed to all insert pumps going forward.

This paper will discuss the early results of approximately 18 months since the first Brush Sand Shields were installed. We will compare the pumps pulled that were stuck in tubing with and without the design change since the implementation. Our goal is to continue to review the trend to see if positive results are achieved. We will track the data and present it again in 2020. We have calculated that the additional cost of pulling tubing is more than 50% more than if the pump can be retrieved with the rods.
 

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. 

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. 
 

Replacing bridge plugs with Perf PODs, to plug/divert individual perforations, allows Operators to divert the stimulation mid-stage and reduce the total number of bridge plugs within a wellbore while maintaining the advantages of closer stage spacing and adding additional clusters.  The risk of a pre-set plug can be drastically reduced, along with pump down time, completion cost and resources associated for the corresponding wireline runs and subsequent millout work.  Applying Perf POD diversion technology between bridge plugs allows the Operator to achieve maximum cluster efficiency, while stimulating the entire stage, without leaving orphan clusters behind.  This ensures a more consistent stimulation volume pumped into each perforation cluster, ultimately providing a more balanced treatment and reducing the probability of a “runway frac”, which could potentially damage offset wells.   

Based on current stimulation design - are you effectively stimulating every cluster?
 

Slippage is required for lubricating the plunger/barrel within beam pumping systems. Increasing pump clearance increases the amount of slippage, which may lead to inefficient operations. Operators could run their field more efficiently through decreasing failure rate and increased electrical cost savings by calculating the optimum design using the Patterson Slippage equation for individual well conditions. This paper will discuss the economic tradeoffs with changing pump clearances and recommend theoretical optimum designs given well conditions. The paper will also include nomographs and a calculator to recommend optimum designs. 

The performance of Harbison-Fischer’s patented Sand Flush Plunger (SFP) was assessed relative to the average runtime for standard API plungers in the HWY 80 field, operated by Pioneer Natural Resources (PNR). The field case study captured information from Harbison-Fischer’s pump-tracker for 5,283 wells and 32,804 workover records dating back to 1989. As of the record date, 1,934 different wells had used an SFP 3,473 times. The analysis focused on 194 wells, for each of whom the data showed at least one failure originated by the pump for each of the two plunger types. The average runtime for the SFP and the API plungers were found to be 1,178 days and 579 days respectively.

The present study constitutes an update on the continuous monitoring of the performance of the SFP that has been carried out in HWY 80 field since 2015 [1]. The number of wells considered for calculating the average runtimes has gone up by 37 wells from 157 reported in 2015. Similarly, the number of qualifying pump changes has increased by 102 from 486 reported back in 2015. The data processing has been carried out using Tableau, and slightly different criteria for cleaning the records have been implemented.

In 2014 Oxy EOR had lost confidence in the accuracy of Fluid Levels in CO2 wells and was not shooting them. Echometer and Oxy collaborated to identify the root cause of the fluid level inaccuracy and resolve the issue through improved procedures and educating personnel. Today trusted fluid level information adds value by improved operational decision making. 

Typically, the Petroleum Industry maintains operational ideas that were developed years ago.  These operational ideas may still have merit, but some improvements should be considered.  Sucker rod guides are an example of such practices.  Most production companies continue to use rod guide material that was introduced at the conception of the recognition of the need for sucker rod guides.  This presentation will give information of new materials and new application ideas for sucker rods guides. 

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. 
 

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. 
 

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. 
 

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. 
 

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. 
 

The cavitation phenomenon has been extensively studied for many years, however, guidelines on how to implement this existing knowledge to the actual operation of the jet pumping systems in the oilfield are not abundant and, as per the author can see it, not yet being presented in such way that the people that operate these systems in the oilfield could implement on a straight forward way. It has been proven that using a scientific and easy to follow methodology, it is possible to prevent jet pump operating problems related to cavitation, during the early, middle and late stage of the well production life. Preventative and Corrective methodologies are based on: Measured production rates, power fluid rate and pressure, gas to liquid ratio, jet pump seating depth and jet pump nozzle/throat combination.

This paper presents a straight forward discussion on the jet pump cavitation, its hydrodynamics, causes, identification, potential damage, consequences on the jet pump performance and methods to predict it and avoid it.

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.

The ESP system is a mechanical/electrical/hydrodynamic system. It is costly when it fails as the tubing has to be pulled and much or all of the equipment is replaced. 
This paper points out tips in the below various areas that if considered are likely to increase the average run life of ESP Systems

-Failure definitions from data
-Design
-Installation
-SCADA-Monitoring
-Tips for running in Harsh Conditions
-Pulling
-Teardown Analysis
-RCFA and follow up
The information summarized includes industry findings and experience from the author’s backgrounds

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.

In some of today’s unconventional wells, sucker rod pumping systems are facing challenges related to excessive wear, affecting production and increasing operational costs. One of the reoccurring damages in a sucker rod pumped well occurs near the kick-off point in a deviated well between the coupling and the tubing or between the sucker rod and the tubing; the metal-to-metal contact causes hole-in-tubing failures and operators have been seeking solutions to mitigate or minimize excessive tubing wear in highly deviated wells. Wear caused by both metal contact and abrasive particles, as well as corrosive attack from the wellbore’s fluid also affects the metal integrity of the tubing, coupling and sucker rod. It is beneficial to develop fundamental understanding on wear and friction concepts in rod lift applications, to optimize rod lift product designs and improve Mean Time Between Failures (MTBF) in deviated wells.

In this paper, the concepts of friction and wear will be explained from applied rod lift engineering perspective. Field tested solutions to reduce tubing wear will be presented with lab and field data.

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.

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.

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.