This paper will cover sucker rod pump barrels that are available in the industry for downhole sucker rod pumps, as well as tapered barrels for pressure balance on the upstroke.  For barrels it will cover their traditional uses, interesting exceptions to API 11AR recommendations, barrel materials and their applications, and tubing anchor effects.  The theory behind a new tapered barrel pump will be covered, as well as the materials used, a unique testing apparatus and the advantages to the operation of the well. 

One of the benefits of utilizing a Sucker Rod Pump for artificially lifted oil and gas wells is that they can achieve total drawdown the casing fluid above the downhole pump. This allows for the artificial lift method to maximize the production of the well by minimizing the back pressure on the reservoir caused by the fluid level in the casing anulus. However, in some cases the original design of the sucker rod pump system may not be able to achieve the capacity required to drawdown the entire fluid level in the casing anulus. In order to increase production operators are tasked with identifying these wells and prioritizing them based on their opportunity for increased production and then perform the necessary operational changes to ensure the wells are producing more optimally. Previously this process was done entirely manually and could take several hours per well. 
To combat this, algorithms were developed to apply rules across several thousand wells to determine if they are good candidates for increase production. Using a host software solution tied into wells running on pump off control, algorithms were developed to determine if a well was pumped off. If this criterion was met well test information was used to infer the well’s maximum production. Then leveraging software with predictive wave equation capabilities, several outcomes where the speed was modulated in the rod pumping system were generated. After analyzing all the possible scenarios, the algorithms then determine the optimal solution based on equipment loading, well performance, and production information. Operators are able to leverage this automated process to determine real opportunities for increased production on the rod lift artificially lifted wells. By automated the process of discovery, prioritization, and speed changes required, the software eliminated unnecessary man hours in the process of optimizing wells for maximum production and allows the end users to quickly identify wells with actionable changes that will lead to production increases. 

Automation has been used for many years now as a means for oil and gas operators to optimize sucker rod pump wells. Traditional automation for rod pump wells involved operating the well at a fixed speed and idling the well based on a preprogramed time (time clocks) or fillage (pump off control). However, utilizing a Variable Frequency Drive (VFD)is a more sophisticated method to allow operators to increase their runtime by detecting when there is less fluid to produce and slowing the unit down, accordingly. Although utilizing a VFD can provide significant improvements in production and failure reduction, in some cases operators are not able to realize the full advantage of their rod pump wells with VFDs because the VFD setpoints are not optimized. Optimizing VFD setpoints is not necessarily challenging, but in many cases requires many iterations of user intervention which takes time, and with the ever-changing nature of some reservoirs, that job may never be complete for a given well. However, utilizing a host software with algorithms developed by industry experts, VFD setpoint optimization can be done autonomously. Using domain-specific algorithms, the host software can detect deficiencies in VFD operations and iterate through setpoint changes to determine the optimal setpoints. Utilizing host software, the algorithms can constantly check to make sure that the setpoints are keeping the well running optimally, even when reservoir conditions change. By identifying issues like excessive cycling, lost production, unnecessary speed changes, and poor pump fillage, the algorithms implement changes that improve the performance of the well and help operators leverage the full capabilities of their VFD.

The objective of this paper is to present oil and gas industry the advancement and improvement of the Baker Hughes ESP phase system on wells with relatively high GLR, moderate water cut, and suggest considering the presented design system in comparable wells for an extended run-life. Paper presents run-life analysis and comparison of a conventional design versus the phase system in terms of power consumption, cost savings, and reductions of the emissions due to differences in surface power consumption between two different ESP systems. Operator after installing the standard design for given well output conditions eventually decided to test the new system on their well to minimize maintenance and avoid consecutive shutdowns on multiple occasions. Three wells will with phase system will be presented in detail to showcase the results and performance improvements. The baseline for the case study is chosen to be real running parameters of three units at different timeframes. Real electrical and mechanical parameters are used to match in-house software and produce power consumption and pump operating conditions which are crucial for a unit run life and therefore operator’s capital investment. In short, it is observed that with an initial design of low GLR, high water cut, and high total liquid rate for a given well standard pump design has been failing to perform and reasons will be discussed later. Further in time, as water cut remained relatively the same on average, total liquid production dropped, while GLR increased, phase system showed better performance and more optimistic expectations of unit run life. Running old design at late time production system at the same frequency indicated more power consumption and therefore higher capital expenditure. The performance of new design allowed for a frequency increase of 7-15% which allowed for more drawdown. This indicates the improvement in power consumption and in turn suggests better efficiency of recovery. The design discussed in this paper is relatively new to the industry and it aims to reinforce and support previous publications. Purpose is to show an implementation of this design on a new case with real performance evaluations. It may be beneficial for number of operators to consider this type of design in their future ESP applications at mid-to-end life of their wells. 

This paper presents new research methods, designs, and field testing of a new type of mechanical gas separator for electric submersible pumping (ESP) systems that increases the operating flow range and separation efficiency performance, while decreasing erosion problems and improving reliability. 

A state-of-the-art test system for measuring and understanding the internal workings of two-phase flow conditions and throughput of mechanical separation devices was used. This testing enabled visual understanding of internal fluid flow, recirculation, separation efficiency, and collective and individual performance of various components of the gas separator. 

The result is an innovative hydro-helical separator system with optimized components. The intake is designed with smooth intake flow paths to maximize flow capability and minimize erosion. Also in the design is a new fluid-mover stage with significantly higher capabilities of handling two-phase flow and gas lock protection. A stationary helical component replaces the dynamic vortex inducer, allowing for more efficient gas separation and increased throughput of the fluids within the separation chamber. The helical component precisely directs the separated fluids with its increased velocity into the crossover pathways. The crossover is designed for maximum throughput, low resistance flow passages, and erosion protection. 

Field testing results show a significant improvement in production and drawdown of the well. The Hydro-Helical™ gas separator is the industry’s new generation of downhole gas separators with the highest flow range, higher efficiency, and reduced erosion. 

Unconventional reservoirs bring new challenges for Electrical Submersible Pump (ESP) Systems, such as rapid decline and high gas production. As these conditions can add obstacles to the operators to efficiently produce the wells, the industry is always looking for opportunities to improve ESP performance. This study analyzes the performance of some successful ESP Applications installed to produce from Unconventional wells in the Permian Basin, Delaware and Midland Basin. Showing what we have done differently as best practices to increase the ESP runlife. 

These are challenging ESP applications, but the way the ESP equipment is sized for the application, the way we operate the system once it is installed, how we optimize the well really makes a huge difference to impact the life of the ESP equipment and maximize the run time. 

This paper will present clear guidelines about how to operate the ESP equipment in the most efficient way.

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

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

The operational and performance advantages of this device have allowed its successful installation several wells in the Permian Basin. After the installation, the run times have maintained high values, thus reducing the interventions to the wells and the replacement of the pumping equipment, thus reducing the carbon footprint of each one of the wells where this technology has been run. Additionally, the sensor variables have remained stable, which contributes to a higher cumulative production compared to periods where the pump was off for long periods, or the wells were under maintenance because of sand production. On top of that, each equipment pulled has been inspected and re-used to maximize the investment increasing the NPV of the projects.  This new technology is the only one with the ability to protect the ESP against solids during shutdown events, allow flushing operations, and being inspectable and repairable. The use of premium materials, along with a special assembly system make it a tool with a long useful life.

Main objective of this paper is to introduce oil and gas industry the new E3000 and E1000 pump models across multiple wells in the Permian and Delaware Basins in term of performance, and operation improvements. It is intended to show a reader pump performance enhancement and comparison to older models based on operator required production rates, pump loads, power consumption and other electrical and mechanical parameters that of the focus when designing and selecting an ESP. 
New pump designs (low volume and high volume) entered the market offering wider range of operation and lower number of stages required to lift a given amount of fluid as opposed to older models, new pumps have steep and consistent rising head curve all the way to shut-in, A higher head rising steepness leads to more prompt H/Q response, delivers better controllability especially when PIP is low and/or the well is gassy. Some operators agreed to try and test new pump designs on different well pads. Opportunity presented itself to study different cases and evaluate the performance of new pumps. Team has decided to compare performance using Baker Hughes software and real-time pump performance curves. 
Having a smaller number of cases with E1000 and E3000 400 series pumps their performance has been simulated on real conditions on wells that were installed with older pump models such as Flex31 and/or P35 by Baker Hughes. Different wells have been picked with relatively similar fluid production, setting depth, GLR, water cut, and other parameters to reduce the discrepancy as much as possible. From economical standpoint newer models offer less cost to an operator and higher system efficiency. From operational standpoint new models offer a smaller number of stages, thus more lift capacity per length. Another observed benefit is that operating range is much wider than on older designs and on multiple occasions older models end up close to the extreme or out of range based on the test flow data. This impacts the run-life of overall unit, reduces the number of shutdowns, and in turn lower operational costs for an operator. Wells with new pump designs will be presented to a reader with real-time operational pump curve electrical and mechanical values. New ESP systems showed up to 5-6% efficiency increase and almost 4-5% power consumption reduction using E3000 & E1000 pumps.
LiftPrime pumps E1000 and E3000 are new models and starting to slowly pick up by the market, more pumps will be also introduced to the market in 2023. Practicing engineers can learn about the performance of these units from real-time performance data, simulation cases, and comparison to older pump designs. The LIFTPrime high-efficiency pump lets operators optimize economics in both conventional and unconventional wells by lowers energy consumption, reduces pump downtime and brings new levels of efficiency, reliability and flexibility.

This paper explains the configuration, design, and mechanisms of an advanced gas regulator system installed underneath the ESP sensor to decrease downtime and stabilize the operational parameters of the pump. The gas regulation principle is based on the changes in the flow regimes found in unconventional wells where typically, gas slugging and high GLR frequently cause shutdowns and motor overheating. 
The case study presented in this abstract refers to a well-localized in Midland Basin that had a history of multiple shutdowns, erratic current behavior, unstable PIP, and high motor temperature peaks, all caused by a combination of high GLR and low fluid rates (for ESPs). The well produced a GOR of 5,959.6 SCF/STB and a GLR of 1,609 SCF/STB with a liquid rate of 330 BPD. The main objective of the installation of the Gas Flow management technology was to allow the ESP to run longer and deplete the PIP without cycling (less downtime) and maintaining constant motor load. After the installation, the ESP has not had any shutdowns due to gas in 3 months, operation frequency started at 50 Hz and then increased to 55 Hz which allowed it to deplete the PIP from 720 psi down to 465 psi.

With the data collected over many years, we can show how we have improved the gas lift valve tear down process, and how that data collected from this process has increased longevity of wells in each, individual area. While following the API Standards of gas lift valve expectancies, both in initial installs as well as reporting once valves are pulled, data is paramount. The ability to provide extensive data, that tracks trends across formations, mandrel types, valve types, and a myriad of other parameters better enables the operator to make the best choices going forward in their wells. This has shown better production from wells that were utilizing the “standard quo”. In this presentation, the aim is to show how more data can be prudent in making better choices for the lifetime of the well.
We have added and improved paperwork for when the equipment is returned from the field so that our technicians can document the equipment, and anything deemed noteworthy. The report, itself, has been greatly improved and mainly focuses on the issues with the system. Long ago, we started tracking extensive data alongside the report. This data can and has provided useful information when making decisions and guides improvements for us and our customers. 
The data from the tear down is placed into a spread sheet for both our and the customers’ records. We record causes of leaks, equipment torn down, equipment pass/leak rate, etc. Using this data, we can track trends and see patterns that improve equipment and well performance. Several trends and discussions have already come from this data. We have used this data to address certain issues faced in very specific formations that allow us to make improvements and provide guidance to our customers for further installations. 
With the continuation of further data gathering in gas lift tear down processes, the production should follow trend in gaining. As for the methods of gas lift, that data set is ever changing; however, we challenge that the more data ascertained, the better the well can produce. As time moves forward so shall we.

The temperature allocation along the well plays a crucial role in the design performance and troubleshooting analysis of gas-lifted wells. The temperature of injection gas at each valve depth should be well-known to establish the gas flow rate spread across every valve. As gas temperature across the valve and production fluid temperature will be utilized to evaluate nitrogen pressure inside the bellow of the valve. Therefore, the temperature is the main factor in evaluating nitrogen-charged gas lift valve closing and opening pressures.

In this case study, real-time measurement of temperature pressure is done through the RTD Quartz sensor in a flowing gas lift well through a wireline. It has a completion with the 2-7/8” tubing in 5-1/2” casing with a packer, with 8 12 port IPO gas lift valves in conventional mandrels with a chemical screen below that. The new survey measured temperature and pressure across each valve in the current flowing condition are lower than the temperature used in calculating Pvc (gas closing pressure at depth) and OP (valve opening pressure at depth) of each gas lift valve. The new temperature was used to evaluate the temperature correction factor, which is then used to update Pvc and OP to justify that every gas lift valve will have new surface controls (surface opening: Pso and surface closing pressures: Psc). 

Once the error in the Dome/bellows pressure originated by estimating a temperature profile lower than the actual value is evaluated, we simulated the error caused by over-estimation of the temperature profile so that we can be ready for wells with higher water cut and high liquid velocity. The accurate temperature measurement at each valve eliminated the prediction process of injection gas and valve temperatures through Shui’s correlation. Also, it helped in finding favorable conditions to prevent paraffin, asphalt, hydrate, and scale creation in late times in the production tubing. 
A systematic approach of updating the surface closing and opening pressure gives operational insights into what was wrong with the gas lift operating envelope. Adjustments were made to pressure production traverse curves based on new conditions using GLDP (gaslift design program). After implementing new conditions backed by the well’s data, the production of the well improved and prevented a possible work-over job. 

Annular flow gas lift has rapidly become a popular method of initial artificial lift in the
Permian Basin. The evolution of wells, over time, has resulted in higher flow rates due to
advancements; this includes horizontal, multi-staged improvements in frac technology. Smaller casing strings are often installed to save on well costs, but this can limit the type of artificial lift system that can be installed, and ultimately, the flow rates attainable from the well. Annular flow options offer a larger flowing area and less of a pressure loss versus tubing flow applications.

This presentation will include some basic inflow and outflow theory to show the difference in  various scenarios. There will be several annular flow gas lift
options explored including fluid mandrels, internally mounted mandrels, standard
configuration side pocket mandrels, EC configuration side pocket mandrels, and hybrid combinations of these systems. These different options will be discussed including the advantages and disadvantages of each system.

The presentation will also share some important improvements in the side pocket EC system. An issue identified with valves coming out of these pockets became prevalent in many basins; an Engineering group studied this and offered up a solution to prevent this from occurring; this resulted in it being adopted by the industry worldwide. These findings and best practices will be shared with the group during this presentation.

Since its’ introduction to the unconventional oil and gas realm in 2017, 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 MIDCON basins. It has become a proven technology with over 1,600 applications to date as more operators are choosing it as their primary form of artificial lift for their unconventional assets. 

One of the primary advantages of HPGL is that its' performance is extremely predictable. Nodal analysis can be utilized to predict production performance and its cost are well defined given there are no mechanical downhole parts that can lead to unplanned, costly workover operations. Another primary advantage of HPGL is its versatility for handling various production regimes. The system is not constrained by tortuous wellbores or solids production, and it works exceptionally well across varying producing GLRs. 

This paper will review several case studies that highlight the predictability and versatility of HPGL across the MIDCON and Permian basins. 

Long lateral, high-rate wells in the Permian basin present unique challenges to maximize rate relative to ensuring flow stability with gas lift. Annular flow gas lift has offered a transitional lift method between high rate casing flow and traditional tubing flow gas lift to maximize well production. However, annular flow and annular flow gas lift have presented a more aggressive corrosion profile on the exterior of 2 7/8" L80 production tubing than anticipated.

Tubing metallurgy or coatings provide an opportunity to mitigate corrosion in an artificial lift system in which overall fluid and gas rates are too high for traditional corrosion prevention chemical application. Specifically, field trials of 1% CR L80 and spray metal coated L80 tubulars in an annular flow system are compared against lab-based flow loop corrosion testing to evaluate economically viable approaches to tubing preservation.

The main constraint in a gas lift system is a limitation on injection volume and surface injection pressure due to the packaging and compressor capabilities available. In an ideal world, the system would have unlimited injection gas volume and unlimited injection pressure. This is often not the case with compressor availability and/or already-existing facilities. These constrains can limit the design and efficiency of a gas lift system. This study was conducted to establish a method that would allow deeper injection without increasing compressor discharge pressure. With limited injection pressure on surface, the system is limited to the injection depth that can be achieved. The design must conserve as much surface injection pressure as possible to maximize the lifting depth. 

A drawback to typical internal pressure-operated (IPO) gas lift valves is that the valves take +/- 25 psi pressure drop/reduction between gas lift valves to transition properly. These pressure drops reduce the full potential of compressor discharge pressure that is available. This decreases injection depth and ultimately decreases production or ultimate drawdown. Although these pressure drops may limit injection depth, they allow for simple monitoring of the gas lift by observing the surface injection pressure. The surveillance of these pressure drops can easily portray any problems the system might be experiencing.

With the constant-pressure design approach and the selection of an alternate style of IPO gas lift valve, an engineer can minimize or eliminate the need to take a pressure drop and allows one to fully utilize the maximum available injection pressure. This is accomplished through valve mechanics where the pressure drop is taken over a choke, rather than the ball and seat. Since the injection pressure stays constant throughout the life of the well, one loses the ability to use the injection pressure to corelate the injection depth. This is a drawback for this style IPO gas lift valve and can make it difficult to determine if the well is injecting at the intended depth.
The goal of this paper is to identify if using a different style IPO gas lift valve as the upper unloading gas lift valves and conventional/traditional IPO gas lift valves for the operating valves would be a useful application to maximize injection depth. Each system included a live downhole pressure gauge. The results from this study showed that deeper injection and higher drawdown were achieved with these systems versus a standard IPO-style design. This study was conducted with Elevation Resources in the Permian Basin.

OBJECTIVES/SCOPE:
As gas lift utilization increases as a form of artificial lift for many assets in the Permian Basin, optimization through gas allocation remains a challenging problem. Operators are often limited on the amount of gas that can be injected downhole due to infrastructure capabilities and added operational cost. In addition to how these constraints impact production, wells may have a higher tendency for slugging behavior. This regime can also be exasperated by high water cuts, steep natural declines, compression issues/inefficiencies, and sub-optimal gas lift injection depth and volume. 

METHODS PROCEDURES, PROCESS:
This presentation provides field and production data illustrating the results of applying CHX Gas Lift Flow Improver (GLFI), an innovative chemical solution for increasing production in gas lift wells. Well selection criteria will be discussed and is critical to application success. 

RESULTS, OBSERVATIONS, CONCLUSIONS:
Through downhole introduction, the gas lift flow improver helps maintain the well flow as enabling gas velocity above the critical velocity needed for gas/condensate flow out of the wellbore by reducing surface tension and apparent liquid density, resulting in a decrease in bottom-hole pressure, mitigating slugging and increasing the production.
CHX GLFIs were designed for medium to high water (>40%) cut gas lift wells, and crude API ≥ 35
An ROI* to the operator was calculated based on chemical cost and monetary gain from increased fluid production.
*Financial measure variables (i.e., $/bbl, $/Mcf/d, dosage, etc.) included in the presentation.

QSO Inc. has developed a product to provide a unique and simple solution to problematic or inefficient plunger lift systems installed in horizontal wells in the USA. QSO’s Patented* Horizontal Check Valve (HCV) has removed the limitations that once burdened the industry in not being able to hold fluid properly in a horizontal well. Our HCV has proven to hold fluid in wells where conventional check valves start failing. Production companies can now access current deeper profile nipple locations without the need to set their bumper springs on expensive tools higher in the tubing just to ensure a seal. By maintaining a fluid column down in the heel of a horizontal well, the plunger lift system’s efficiency is maximized, which yields an increase in both fluid and gas production, reduces the frequency of “dry” plunger arrivals, eliminates swabbing and many other remedial well operations. 

An ongoing challenge for industry is the maintenance of stuffing boxes used in rod pump wellhead applications. This important component is the primary interface between the well and the environment and the correct functioning of this system is crucial for operators. Traditionally, the maintenance and adjustment of these devices has been performed manually, with field operators visiting wellsite daily to inspect, adjust and maintain the components.

In 2021 an initiative to automate this maintenance process was initiated. Early field test data was acquired and designs for new equipment developed, along with appropriate control systems. Various new elements of the system have recently been deployed into field operations and results obtained. The data sources are from multiple fields and operations, acquired under varying environmental conditions.

This paper will present the latest data and designs, along with results from the new field test data. Analysis will be presented that gives insight into how the systems can be further developed and refined. 

Continuous sucker rod had been used for many years in sucker rod pump applications. However, several challenges have limited its acceptance in the past. The availability of service equipment, welding methodology, and selection of metallurgy all contributed to premature failures and operator frustration with the timeliness of installation and repairs.

A new approach to implementing continuous rod started with establishing a robust service infrastructure to install and repair the rod. Improved welding procedures and personnel training addressed a frequent point of past failures. Changes in the design approach and sizes used enabled new opportunities that may have previously not been addressed with continuous rod. A shift to metallurgy more similar to the predominant grade used for conventional sucker rods aims to improve fatigue resistance of continuous rod in corrosive environments.

The changes in material and service capability are enabling longer run times, reduced workover time, and extending the capabilities of rod pump wells to produce greater volumes at deeper depths. Multiple installations in the Permian Basin will be discussed to demonstrate the recent successes seen with continuous rod. 

Black Mamba Rod Lift debuted in 2019, shipping its first Complete Rod Control sucker rods in Fall of 2020. Its use has expanded across the globe in a variety of wells and drill styles, meeting various needs of operators. In 2022, Chevron began piloting Black Mamba’s Complete Rod Control designs and product in complex, problematic wells. Alternate solutions were also deployed simultaneously in similar well-bore trajectories.

The results, lack of holes-in-tubing, ease of service and installation has provided reliability to the operator on steel sucker rods starting in June 2022. Monitoring these wells and their successes to date then generated interest in testing and providing Complete Rod Control on fiberglass sucker rods. In January 2023 – Black Mamba tackled the challenge and deployed CRC Fiberglass Rods.

A review of these installations and operations will be provided by the operator, both in all steel rod strings and in hybrid glass/steel strings.

There is a need in the industry for a predictive program that can mimic the vast combinations of downhole pump conditions that are found in sucker rod pumped wells. In this paper, we introduce a software that is capable of showing the all of the basic downhole pump conditions, as well as combinations of these conditions in both vertical and deviated wells. The software can show the ideal downhole card as well as what would be expected to be observed in an on-site rod pump controller. The utility of the software is at least multifold. It not only functions an exhaustive design tool, but it also serves as a tool to optimize the well and generate numerous pump conditions to aid in training personnel to better analyze wells. Finally, the forward looking idea is that this program now functions as the most robust software to produce training sets for downhole card classification and other machine learning tasks.

Following Best Recommended Practices adds value, this paper will discuss selected Best Practices.
1. Tensile strength historically is used as an essential criterion in rod selection. The primary cause of sucker rod failures is not due to exceeding the tensile strength threshold but is due to compression from the polished rod velocity exceeding the plunger velocity. Value can be added from loading up rod strings.
2. Operating a sucker rod lifted well with incomplete pump fillage or in wellbores with severe mechanical friction will result in high failure rate, even when applying best practices to the operation of their wells.
3. A specific design and size of a gas separator determines the maximum liquid rate that will not entrain gas into the pump intake. This rate is defined as the Separator Liquid Capacity. If the pump displacement exceeds the separator liquid capacity, then gas separation will fail and the producing efficiency of the well will be poor. Proper gas separator selection requires that pump displacement not exceed gas separator liquid capacity. The gas anchor length is a significant factor in the number of incomplete fillage cycles. Too long of a gas anchor results in gas breaking out. This is particularly damaging when operating with pump off controllers. The gas collects below the standing value and is processed at start up.
4. Properly setting sucker rod pump clearances maximizes value. After the Patterson Slippage Equation was developed, industry began opening pump clearances. It was believed this would improve solids handling and decrease failures. When pump clearances are too large, the results are 1) increased energy cost, 2) increased failures from increased polished rod velocities to lift the same volume, and 3) increased capital investment to surface the same volume.
5. It is a common practice for operators to delegate responsibility for down hole sucker rod pumps to pump companies. Inspecting the failing component is usually required to identify and understand cause(s) of failure. Part of failure analysis is to be present when failed equipment is pulled from the well and to attend to the tear down of pumps when repaired at the pump shop. Delegation without proper oversight can increase costs. Oversight procedures should be included in Best Recommended Practices. When pump repair volumes are adequate, it may add value for operators to own pump shops.

Incomplete fillage conditions where the downhole pump does not completely fill up with incompressible liquid have been widely accepted to have detrimental effects on pumping efficiency and moreover the equipment longevity in sucker rod pumping applications. Methods of synchronizing the pump displacement to the wells inflow and thus reducing incomplete fillage has been of keen interest to the industry. During operation, surface sensors are used to monitor polished rod load and position to obtain a surface load vs position graph. Concurrently, a pump load vs position graph is generated by solving the 3-D wave equation for deviated wells in the diagnostic mode. Pump fillage is computationally detected with an mathematical algorithm that accurately estimates the Travelling Valve Close (TVC), Standing Valve Open (SVO), Standing Valve Close (SVC) and Travelling Valve Open (TVO) points in the pump dynamometer card. A sophisticated pump off control (POC) algorithm called Advanced Fillage Mode (AFM) with a continuous feedback mechanism is then implemented to significantly reduce incomplete fillage pumping cycles using a variable speed drive (VSD) for speed control. 

AFM accepts the pump fillage set point, maximum SPM and the minimum SPM as the three operational parameters. AFM continuously monitors the pump fillage ,compares the pump fillage on each stroke to the fillage set point and dynamically adjusts the SPM of the well to maintain pump fillage near the fillage setpoint. This synchronizes the pump’s displacement to the inflow of the well.

Additionally, various versions of AFM are available depending on the tolerance for incomplete fillage. In pumped-off or near pumped-off situations, the tolerance for incomplete fillage is very low. Whereas, in cases with fluid level above the pump where incomplete fillage manifests itself as gas interference, one may have a higher tolerance for incomplete fillage to pump the fluid to the surface. A ‘Fluid Level Above Pump’ (FLAP) parameter is available where a user may select the FLAP threshold for controller bias. 
AFM is an intelligent algorithm that determines its key pump off control parameters such as the rate of SPM increments, rate of SPM decrements, observation cycles and stoppage time automatically. Additionally, AFM uses a continuous feedback strategy to continuously optimize the operational variables based on the well’s performance. We will present several before and after case studies to demonstrate the advantages of using AFM. 

Surface coatings are often needed for sucker rod pump components to protect them from the harsh downhole environments of corrosives, formation solids, and even treatment chemicals. Most coatings have both positive and negative characteristics in protecting from each of the downhole aggressors, therefore further precautions must be taken to ensure the survival rate of components, given the economics of wellbore interventions. 

A common dilemma when using chrome plating on barrels is although the high hardness is capable to protect against solids abrasion, the very method to effectively stimulate a well is proved to be detrimental to chrome. Hydrochloric Acid (HCl), a commonly used ingredient in stimulate solutions, will dissolve away the chrome when in contact. Once the chrome is compromised the life expectancy of the pump is greatly reduced. 

Therefore, better understanding the deteriorating effects that acidizing has on chrome will better inform users on how to protect downhole equipment. Is the acid concentration and soak times being implemented too risky? Are they too conservative and sacrificing possible extra wellbore stimulation? 

This study focuses on discovering the degradation rates of chrome coatings when placed in various concentrations of HCl solutions to observe the survivability of one of the industry’s most useful coatings. 

Since becoming a Lift Specialist in November of 2019, it was very clear we had significantly higher failure frequencies on wells with 4.5” liner, 2 3/8” tubing, and 1.75” tubing pumps vs other configurations. My knowledge is solely based on South Plains and the problems we faced.

One of my counterparts had reached out to the pump shops to understand how we could beef up pull rods. It was discovered that a 1 1/16” pull rod could be ran in 1.75” and 2.00” insert pumps. We began taking this route immediately. This got me thinking…What could be ran in a tubing pump to help beef up the pull rod/stabilize it better? We had a few different options that had been done in the past. Land the pump barrel in tension above the TAC to create better stabilization vs. leaving the pump at the bottom of the hole allowing for movement. We could change our pull rod and increase the diameter from 7/8” to a 1.25” sinker or polished rod for more durability. 

Several weeks later we went on a field trip to a pump shop and I noticed a small Black Mamba guided rod on top of one of their racks. It was a ¾” rod with guides fitted for 2 3/8” tubing. Immediately I knew there was no way any conventional guided rod would scope in and out of a tubing pump barrel, but asked myself; could this be retrofitted to work since the entire rod is basically a guide? A Mamba rod cannot buckle due to the end-to-end rod control that 7-per Mamba rods provide. There should be less erosion tendencies downstream of the guide due to the pattern of flow (vortex vs. conventional vertical flow). The vortex movement of fluid discharging at the pump should help keep gas in solution similar to the tangent flow cages we had tried in the past in insert pumps. Compression in tubing pumps was something we continued to struggle with in CO2 floods. I said to myself, “Self, this just might work!”

I thought on the subject for about a week and decided to voice my idea to the QA group. We then got in touch with Black Mamba to see what could be done to test my theory. Black Mamba was very enthused and on board with designing to our needs. They ran computational fluid dynamic simulations (CFD) to help determine the best flow options for Black Mamba guided rods, comparison also to large diameter sinker bars. It was agreed to run 1” Mamba sinker rods above the pump, and to use mamba guided rods at every taper break (4 mambas each side of the taper break in every taper) in conjunction with the plunger stabilizer rod, a unique dimension Black Mamba guided 3/4” Norris N90 (DS/KD) sucker rod.

I had already began collecting data prior to this idea. The data I pulled on 88 wells with tubing pumps was to determine the best design of landing the pump barrel in tension above the TAC or at the bottom of the tail pipe. Failure mechanisms were primarily split barrels and broken pull rods due to wear or coupling breaks. Preliminary results showed that the barrel in tension had significantly longer RT than the barrel landed below the TAC (> 2 years on average). Understanding there could be some production loss associated with raising the pump above the TAC, how do we balance production and longevity? Was there a way to get the best of both? Either way, the answer was the pump should be stabilized to gain the best results.

10 wells feature an End-to-End Rod Control Pull Rod from Black Mamba. Design and application results will be reviewed.