The perceived impact of chlorine dioxide (ClO2) on the corrosion of steel used in the oil patch has been a controversial issue for many years.   Although a few studies on this issue have been published, those results have been contradictory. As concerns surrounding this issue continue to be raised, a systematic study has been undertaken to understand the corrosive effects of ClO2 towards steel in various produced waters.  Research shows that the baseline corrosion rate of untreated produced water is related to TDS, with other factors being involved, such as the presence of H2S and iron. This paper summarizes the results of other studies that have been done, and demonstrates the contradictory nature of such studies. The results of this on-going study show the relationship between the TDS of produced water and corrosion resulting from use of varying concentrations of ClO2.  The paper explains the contradictory nature of corrosion caused by ClO2.

Wells with high depletion rate present high free gas at pump intake conditions. In all cases, the production of fluid with a high gas-liquid ratio leads to an inefficient performance of the rod pump systems. The initial solution to this problem is the installation of poor boy gas separators which capacity of gas separation is reduced and do not provide a high-performance solution.  Packer type gas separators are the most efficient downhole separators in the market, however, they usually have some operational limitations. This paper summarizes a new design of the packer type gas separator which uses more methods of separation than the traditional design and can be designed based on the conditions of each well overcoming the typical limitations. The design criteria are reviewed, and some operational guidelines are listed to reach the best performance in each application for gas separation.

When optimizing a reciprocating rod lift installation, key control parameters must be extracted from the downhole data. Traditionally, downhole data in the form of position and load data is derived from surface data using the wave equation. Downhole position and load data must be carefully analyzed to extract key control parameters for reciprocating rod lift optimization.
IRIS introduces a new and innovative approach for downhole data analysis.

Through a change in coordinate system, IRIS transforms downhole position and load data into polar coordinates. This change in coordinates creates three new data sets, which greatly simplify the extraction of the above mentioned key control parameters.
Additionally, IRIS can be used to manage both viscous and mechanical friction through an extra friction detection algorithm and a viscous damping estimator.

In this paper, the IRIS algorithms and results are presented.
 

As fluctuations in oil price continue, the industry has changed and is demanding improvements from each method of artificial lift. Required flow rates are increasing due to the longer laterals of new horizontal wells being added to inventory. Rod Lift is not immune and is being asked to enter the artificial lift cycle earlier and support the pumping of wellbores with added complexities due to geometries and/or production demands. The fiber reinforced plastic (fiberglass, FSR) rod continues to meet the ever-increasing demand and complexities. The two previous editions of ‘IT’S ALL ABOUT THE END FITTING’ focused on the design of the new generation of fiberglass rod, the added strength the industry has requested, the benefits regarding the handling of compression and methods to mitigate uncertainties of the wellbore dynamics. This edition will focus on benefits of the latest generation of the end fitting. It will explain how a new configuration of the wedge profile provides reduced pressure drop at each connection and/or adds corrosion resilience. The new wedge profile also increases the ability of the end fitting to handle compression. Data will be provided in support of increased production. The fiberglass rods have been delivering benefits for the last 30+ years to the industry and continue to maintain pace with growing demands of artificial lift through innovation and development of new generation FSRs. With an ongoing progress of FSR technology the glass rods are being adopted earlier in the well’s life cycle requiring us to make the product RUN LONGER & PRODUCE 

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. 
 

Oxy Resources established the Texas Delaware Team in April 2013 when ~200 wells were purchased in the area of Pecos, Texas.  These primarily vertical wells produce from various commingled Delaware intervals located at 8,000’ to 12,000’ deep. The nature and deviation of these wells have made rod pumping them challenging and failure frequencies have been as high as 1.5 failures/year. Many lessons have been learned in driving the failure frequencies down to the current level of 1.0 failures/year. This paper will share some of the lessoned learned using various equipment types including fiberglass COROD, Poly-keytone Lined Tubing,  Poly-keytone Rod Glides, and Variable Slippage Pumps. 

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. 

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.
 

Rod pumps are not the ideal system of lift when it comes to handling gas. We can only do so much with the configuration downhole especially for wells with open hole completions. Despite the limited options, we are coming to find that we can do better by manipulating parameters at the surface. Historically, we have manipulated back pressure on the tubing in order to control when gas breaks out of solution in the tubing. Now we are finding, on certain well types, that manipulating back pressure on the casing in order to keep gas in solution through the pump is proving to be successful. By doing this, we are seeing beam wells that now face less equipment stress due to gas interference, more consistent, stable run time and production on a daily basis, and even optimized inflow where production increases for wells. 

There are many challenges associated with sucker rod lift in deviated wellbores that can lead to high failure rates and lost production. Tubing failures are amongst the costliest workovers and are often a result of metal to metal contact between the rod coupling and the tubing. Evaluating tubing on-site using both gamma and electromagnetic inspection allows for proper design optimization before returning to production. The tubing scan can be aligned with deviation data, previous rod design, and failure history to adjust the string design to effectively extend mean time between failures and improve asset value. An effective rod guide strategy was developed to mitigate tubing wear using proper guide type, material, and placement. The implementation of this strategy has helped to maximize production efficiency across the asset. 

The common surface chemical applications cannot reach or have low efficiency due to high fluid levels. This paper Introduces a new chemical technology for all types of artificial lift systems that guarantees an efficient downhole treatment at the entry point and summarizes the applications of this revolutionary method established to deliver chemical combinations by microencapsulating the compounds and packaging the completed formulation in a chemical screen that is placed at the bottom of the tubing (BHA) below any type of artificial lift systems. The new downhole Chemical treatment technology were designed and successfully applied in 3 wells in the Permian Basin to control scale and corrosion. The installation of the chemical tool is easily made up below the pump intake and not additional equipment is needed in the pump or in the surface facilities.

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.

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.
 

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. 

 Unplanned rod lift system outages often lead to long and costly repairs in addition to direct production loss. Leveraging design knowledge of the rod lift system combined with real-time condition monitoring represents a promising avenue to mitigate this problem. This study will demonstrate an application of advanced monitoring and diagnostic analytics on data from vibration, strain, current and voltage sensors installed in critical locations of a beam pumping unit.

When pumping conditions deviate from the norm, the operators are alerted with regard to pending failures, and a supervisory control layer takes immediate action to adjust the operational pumping speed profile to maintain production at a safe operational level or shut down the equipment in the event of imminent catastrophic failure.

This paper will review the sensor installations and data acquisition approach. Experimental field test results will be presented and discussed.

During the down stroke the plunger in a rod pump must fall through a barrel that is filled with fluid. The plunger will establish a free fall velocity that is determined by the forces resisting downward motion. The free fall of the plunger may not be large enough to correspond to the actual velocity necessary to match the pumping speed set by the pumping unit. In this case the plunger must be pushed into the barrel by a compressive force in order to match the pumping velocity. The compressive force may be large enough to cause buckling in the lowest section of sucker rods. The purpose of this paper is to test this hypothesis by presenting measurements of the free fall velocity of a plunger in a liquid filled barrel and the pushing force necessary to exceed the free fall velocity of the plunger in the barrel. Simple models are shown to relate the measurments to practice.

Variable Speed Drives (VSDs) are a popular rod lift control system for operators that are willing to pay a premium for the promise that they can squeeze every last drop from a producing formation. However, initial results from the Eagle Ford suggest that VSDs may not be worth the additional expense when compared to the performance of their less complex cousin, the Pump-Off Controller (POC). In particular, high CAPEX and maintenance costs along with performance issues on gassy, sand producing, shale wells are leading some operators to choose POCs over VSDs for unconventional reservoir applications. 

Furthermore, brief disruptions in production have less of an impact on the reservoir inflow of tight shales than that of higher permeable conventional reservoirs. This study is based on the examination of the performance of Eagle Ford wells that were initially controlled by VSDs and then swapped to POCs.

Variable Speed Drives (VSDs) are a popular rod lift control system for operators that are willing to pay a premium for the promise that they can squeeze every last drop from a producing formation. However, initial results from the Eagle Ford suggest that VSDs may not be worth the additional expense when compared to the performance of their less complex cousin, the Pump-Off Controller (POC). In particular, high CAPEX and maintenance costs along with performance issues on gassy, sand producing, shale wells are leading some operators to choose POCs over VSDs for unconventional reservoir applications. 

Furthermore, brief disruptions in production have less of an impact on the reservoir inflow of tight shales than that of higher permeable conventional reservoirs. This study is based on the examination of the performance of Eagle Ford wells that were initially controlled by VSDs and then swapped to POCs.

A discussion on different types of corrosion and wear (and their associated mechanisms) will be followed by an overview of commercially available mitigation techniques including their practical field applications downhole. Commonly available information that can be used to determine exactly why downhole failures occur will be reviewed.  The importance of using preferred life extension procedures to maximize the Mean Time Between Failures (MTBF) and solve the root cause(s) of downhole failures are also covered.  Finally, this paper includes a review of various metallurgical options, nonmetallic materials, chemical treatments, mechanical methods, liners and coatings currently used downhole focusing on the advantages and limitations of each product.  Commonly accepted practices and myths about downhole corrosion and wear will be exposed.

The objective of this paper is to assist production, completion, artificial lift and enhanced recovery engineers in understanding and avoiding downhole corrosion and wear failures cost effectively.

 The concept of Pump Stroke Optimization was introduced in September 2015 at the ALRDC Sucker Rod Pumping Workshop.  Significant benefits to the sucker rod pumping system are obtained by preferentially slowing the downstroke (when pump capacity exceeds a wells productivity), while keeping a fast upstroke. These benefits are: Less pump slippage, less gas interference, and higher pump fillage, which results in less strokes per day for the same production, which results in less downhole wear. Higher minimum load translate into less rod buckling forces. 

Pump Stroke Optimization also includes automatic adjustment of upstroke and downstroke speeds to keep from overpumping wells, and is particularly effective for horizontal oil wells.

The results of a 20 well 2016 test program will be presented.

Depressed oil prices drive producers to reduce operating expenses and maximize profit margins. Some of these expenses are necessary for day-to-day operations, and are dictated by vendor pricing. Others are a function of the operator’s activity, and can be controlled within certain limits. Workover costs are a prime example of these “controllable” expenses. That being said, well failure control programs are essential to maximizing profits and limiting expenses.

In 2014, Resolute Energy recognized the need for a more effective failure program in their Gardendale, TX asset. Through organizational, managerial, and engineering efforts, Resolute successfully decreased well failures by nearly 90 year-to-year, resulting in expense savings of nearly $4.5 million. 

These savings, along with other expense control efforts, cut lifting cost in half throughout the 101 wells. This paper describes these control efforts in detail to reinforce their importance, particularly in current market conditions.

Field case studies for the patented Sand Flush Plunger™ (patent #8,535,024) have been performed at the Hwy 80 field operated by Pioneer Natural Resources. Pump repair and well conditions data was collected from the pump and well tracker systems used by the service providers of the field. 

Standard pump repair information dated since 1989, while the Sand Flush Pump begun usage on 2009.  Interestingly, the results show that the average run time for the Sand Flush Pump is 840 days out of 560 well workovers that used it, while for a Standard Pump (Metal and Grooved Plunger) is 561 days out of

5313 workovers. Within the 560 wells that have tested the Sand Flush Plunger, 165 used both types of plungers providing a more detail correlation. From these, the Sand Flush averaged 1307 run days compared to the 604 days of a Standard Pump.

Gassy low pressure stratified reservoirs require special jet pump well completion and equipment selection considerations. These reservoirs often experience a 50% reservoir pressure decline within the first 14 months of production but can continue to produce for many years below the saturation pressure. Jet pumps can be installed in wells in many ways. The most common, lowest cost and simplest well completion design is the “casing free installation”, but as reservoir pressure declines below the saturation pressure, gas liberation often results in gas accumulation and slugging under the casing packer that is used in this design.

Beam pumping systems have proven successful in the Permian Basin for many years. The beam pumping system allows gas separation and gas flow up the casing annulus. A concentric coil tubing jet pump well completion offers downhole gas separation with options to improve desired effects. Successful case histories are presented to support the application.

We will show in multiple cases studies the effect of relieving back pressure on a oil well has in relationship to the producing bottom hole pressure, pump efficiency and over all economics of the well.

Metal to metal contact shortens the run life of both tubing, steel and fiberglass sucker rods.  Using sacrificial rod guides can extend this life at the expense of increased side and axial loading enhanced by Coulomb friction effects.  The problem is not limited to directional and horizontal wells.  Just how crooked are our vertical wells?  Simple inclination surveys insufficiently describe the wellbore path drilled.  Knowledge of failure history, inclination and azimuth of wellbore path, plus access to a rod design program provide insight into effective placement of rod guides and longer run life.  A case history from an established West Texas waterflood is presented to illustrate the application.