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.

Corrosion and fatigue are the primary causes of sucker rod failures in artificial lift systems. Harsh well fluid conditions lead to material loss and detrimental pitting which then lead to initiation points for fatigue fractures to occur.

Production in aggressive service environments with higher acid gas concentrations associated with increased levels of hydrogen sulfide (H2S) and carbon dioxide (CO2) requires good fatigue life associated with corrosion resistance. 

Manufacturers have therefore been challenged to improve products in order to provide reliable technology to overcome industry needs extending production feasibility as long as possible. 

High Strength Low Alloy (HSLA) steels have been widely used in decades to provide fatigue resistance, however the corrosion resistance of such steels is of concern. High-chromium steels have recently been utilized to improve performance, but their corrosion resistance is limited along with their fatigue performance. The development of a true martensitic stainless-steel grade aims to improve corrosion resistance, extend fatigue life of sucker rods and reduce overall operating costs. 

This paper presents the development of a true stainless-steel chemistry with field performance in successful applications throughout Permian Basin and Bakken.

Producers can spend a significant amount of money repairing a sucker rod pump system without fully understanding the root cause of a failure. Incomplete, missing or incorrect data and over reliance on a supplier to “fix the problem” can be ineffective. Following “best practices” developed in other fields or generic “rules of thumb” may also lead to higher than expected failure rate especially in unconventional reservoirs.

Common practice of a “like for like” replacement may experience an early life failure resulting in another workover. This increases lifting cost and contributes to unfavorable well and field economics.

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.

A process for modeling multivariate Electric Submersible Pump data in a central host system is proposed in to support managing fields by exception by using artificial intelligence models to identify failure modes and operating conditions. The AI model enables operators to immediately identify failure modes and operational conditions, as it is continuously analyzing, facilitating quicker decision making. It also increases the number of wells an operator can effectively manage, and can be used as an educational tool, empowering users to interpret complex ESP trends. Methods, Procedures, Process: The approach to Electric Submersible Pump trend analytics is based on field data observed from over 1400 wells across the United States. Standard trend data for ESPs such as Motor Frequency, Surface Motor Current, Downhole Motor Temperature, and Pump Intake Pressure are considered in the model. A process is described for cleaning and standardizing raw sensor data, detecting anomalous operating conditions, and classifying the anomalies using multivariate statistical analysis. The model recommended is extensible to consider arbitrarily many sensor signals in classifying the anomalies. Results, Observations, Conclusions: Upon sequential iterations the accuracy of operational conditions classifications improved to about 80%, and eventually achieved 90% accuracy after multiple validation cycles on the 130 test ESP wells. We determined the algorithms we are using to classify operating conditions limits the accuracy but increases the meaning to the end user by the way it is presented. There are more advanced algorithms available with the potential of achieving higher accuracy but at a cost of understanding and explaining the results to the user. The broken shaft and gas slugging cases studies presented in this paper showcase the value driven by the model’s ability to identify failures and operational conditions that allow expedited planning of resolution procedures. Thereby reducing the downtime of high production ESP wells and the impact of lost production. The model presented in this paper will continue to expand into more classifications over time. Further work is required to build out recommendations for ‘next-steps’ based on the classifications presented. This will enhance the understanding of why the anomaly is occurring and the steps to take to resolve the problem. Continuing on this path will inevitably lead us to the beginning stages of autonomous control. Novel/Additive Information: The ESP community is adapting to new ways of analyzing trends over time. Circular ammeter charts were the only piece of downhole information available for many years. As downhole sensors became standard in the industry, new variables became available but that also meant the learning curve became exponentially steep overnight. This method for analyzing Electric Submersible Pump trend data is novel in the diversity of its data sources (over 1400 wells representing diverse reservoir conditions and well designs) and in its ability to generalize wells with diverse sensor configurations and levels of data quality/availability.

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.

Harmonic Mitigation Challenges in Unconventional ESP Applications 1. OBJECTIVES/SCOPE: Modern oil field producers face increasing pressure from utilities regarding harmonic compliance, and harmonic-related penalties can be severe. A more effective approach for mitigating VSD-induced power harmonics is presented, in which the unique electrical requirements of unconventional ESP applications are considered. The results of a field study demonstrate how a unique application of passive filter technology is far superior (both in technical performance and cost/benefit to the customer) when compared to outdated 12,18,24 pulse drive architectures and even AFE technology. 2. METHODS, PROCEDURES, PROCESS: Ensuring optimal harmonic reduction for VSD/ESP applications requires a more comprehensive approach, as well as a new application of established technology and new monitoring methods. Historical load analysis, field survey data (direct harmonic measurements), and consideration of future electrical loading changes must all be taken into account in a successful project. Moreover, verifying harmonic mitigation compliance in line with applicable standards requires new measurement methods, technologies, and planning. 3. RESULTS, OBSERVATIONS, CONCLUSIONS By focusing on field-scale harmonic reduction as opposed to performance at individual well sites, a better outcome for the customer and the supplying utility can be achieved. A field harmonics study encompassing 22 individual well sites is presented and harmonic current distortion reduction results out-perform utility requirements. Comparisons of various mitigation topologies are presented as they relate to the unique challenges of steep production decline applications, as well as challenging modern oilfield power quality environments. A new passive harmonic mitigation architecture is presented that adapts to changing electrical load, ensuring harmonic reduction is optimized as electrical loading declines. In addition, harmonic measurement methods and monitoring are discussed as they relate to recent changes in IEEE and IEC standard requirements and as an effective means of managing the routine maintenance requirements of passive harmonic filters. 4. NOVEL/ADDITIVE INFORMATION This paper will present realistic considerations and examples of real world results for the specifying engineer, when considering harmonic mitigation technology in unconventional VSD/ESP applications. In addition, new methods of employing remote power quality monitoring are presented which can prove invaluable to continued, reliable operation and compliance with applicable standards.

There is a growing awareness in the oilfield of the problems generated due to horizontal wells’ long lateral lengths, undulation fluid and gas trapping capabilities, inconsistent and aggressive unloading behaviors, and limitations on historically and widely applied separation methods.  Due to these impacting factors, horizontal rod pumped wells must address the resultant production behaviors as well as operational issues that can be worsened by poor application of old and non-optimal downhole separation and poor pump placement practices.  It has now been proven in a multitude of applications and formations across the US that the use of a safely and correctly placed isolated tailpipe used in series with a diverter style of separator can help alleviate challenging production issues in horizontal rod pumped wells, resulting in substantially increased production output as well as reduced failures and lower operational costs.    

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 last few years there has been quite a bit of advancement in the fiberglass sucker rods (FSR).  The published ratings across the fiberglass industry have increased over 20% with some manufactures going much higher.   What other benefits have come along with this increase?  Have there been any drawbacks?  This paper will discuss proper design criteria including importance of well specific criteria.  With load ratings increasing as much as they have a better understanding of the dynamics of the wellbore are needed as many companies are realizing further cost savings by substituting smaller rod body diameters and getting similar productions.  Lastly this paper will present some preliminary data on compression testing being performed and how that has correlated into the successes for the FSR installed in the field.

This paper discusses the principal of ball lifting systems (Lizard) for oil and gas wells and its possible applications. Typical applications are: 1. Acts as moving standing valve to minimize dry runs while reducing tubing wear. 2. Will continually operate in transition area; Lizard will move the to transition flow area to deliver ball to lifting sleeve, unloading wells and work itself to the bottom. 3. Increase lifting depth from 40 degrees to 75 degrees. 4. Stop yo-yo effect between two-piece plungers. A Lizard assembly for a plunger lift system is used to remove fluids and hydrocarbons from a subterranean wellbore includes a ball lifting sleeve meant to act as bumper spring or sit on bumper spring that engages (e.g., unites) and disengages with plunger assembly. The sleeve acts as an orifice to capture hydrocarbons from dead space around bumper spring and centrally force hydrocarbons to plunger assembly with maximum velocity. The ball lifting sleeve provides transfer of ball and liquid column to lifting plunger and assists in transitioning flow area. The sleeve provides softer fall rates reducing damage to lifting plunger and bumper spring. The Lizard assembly provides higher quality plunger operation further down curvature of deviated and horizontal wellbores providing deeper lifting capabilities. The sleeve provides standing valve principles to horizontal and vertical wellbores. The Lizard will unload high volume liquid loads by acting as a movable standing valve and gradually working its way to bumper spring. The Lizard can be utilized to replace bumper springs, reducing tubing restrictions downhole.

Production testing with digital electronic devices has been discussed for about 20 years amongst a small group.  The idea has been implemented a few times with uncertain results.  The uncertainty exists because the measurements were done with turbine meters which are themselves uncertain.  

Recent testing has been accomplished by gauging calibrated tanks.  We believe these measurements of liquid volumes can be viewed as perfect.  Measurement of gas is done with computerized orifice meters which are known to be accurate as long as the correct orifice size is used.

This presentation compares perfect production tests made with tank gauges and test made with imperfect digital-electronic devices.  What would the oilfield look like if testing with digital0electronic devices became the norm?

 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.

Horizontal Unconventional declines have a rapidly declining hyperbolic decline section and a slower declining exponential decline section. Rapidly changing production volumes from the decline curve and more rapid changes from slugging gas as a result of undulations in the horizontal leg plus sand from massive frac jobs result in challenges in artificial lift selection. This paper will explore these challenges.

The conversion from ESP to rod pump is needed when well-inflow is insufficient to supply enough fluid to the ESP. However, achieving good pump performance in rod pump systems operating in depleted wells with high gas/oil ratio can be limited as well. Creating a multi-stage gas separator system which removes free gas before fluid entered the pump intake increases volumetric efficiency in depleted wells. The first stage is a slotted intake where gas can coalesce. The second stage utilizes three large gas separator bodies for increased expansion of free gas which travels with the fluid by action of an extended dip tube. Finally, a vortex tool which creates a centrifugal force increases free gas separation efficiency.

A successful case study in Goldsmith is presented in this paper to demonstrate significant pump efficiency increase resulting from enhanced separator design based on downhole conditions to create a more efficient production system.

 

Gas production is one of the main problems on ESP systems; causing premature failures and low efficiency, these are the reasons why many companies have developed a number of solutions to separate gas before reaches the pump. To solve this problem a New Downhole Gas Regulator has been developed in order to avoid large amounts of free gas flowing directly into the pump intake. This system regulates the amount of gas ingested by the pump so it will make easier for the pump stages to lift a fluid with a higher density (Less amount of gas in the multiphase flow). The system was designed to use the free gas flowing upward with the liquid to re solubilize the gas into the oil and produce the fluid with the lowest GOR and highest Rs possible. The ESP’s Downhole Regulator was designed based on each well conditions to maximize its efficiency.

 

Poor performance in rod pumping wells using downhole gas separation tools is not uncommon. The stems from a lack of evaluating well conditions before inserting a template gas separation tool which can handle liquid production and free gas in the system. Evaluating well conditions before designing the downhole gas separation tool while applying static & centrifugal principals have led to increased success for recent installations.

This paper reviews cases studies where evaluations of well conditions dictated BHA design for downhole gas separation systems and improved the overall pump efficiency in poorly performing wells with high gas volume.

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.

This paper proposes an analytical methodology that consists of an evaluation of the particle size distribution, viability for the use of sand screens and centrifugal separation systems for sand control management in wells with high sand and fluid production producing through an ESP. All the technical considerations are explained focusing on the information required and the parameters analyzed to recommend the most accurate design for sand control; selected approaches and models that have been developed to improve the runtime due to sand issues. The methodology for the evaluation and selection of sand control systems was proven in a field with historical low run time due to sand problems in the ESPs. The methodology is explained with the theoretical concepts and through several case studies in the Permian Basin.

 

Sandy wells are a common problem for any artificial lift system. Calculating the correct allowable volume of sand and solids’ particle size may be the missing link in optimizing run-times and establishing solid pump performance.

Recent Colombian ESP case studies were conducted in fields with high sand/solids presence. Where run times typically lasted 5 months or less, a new design to improve ESP performance introduced a Cup Packer and screens below the ESP sensor.

Once ESP variables such as intake pressure, drive frequency, and temperature were considered, the unit conditions stabilized and improved performance followed, greatly extending run times, and reducing unnecessary intervention costs.

 

Carbon fiber sucker rods were first installed in wells in 2015, and significant material and design improvements have been made since. Originally developed to rod pump the deepest wells with small-diameter tubing, high-strength, light-weight carbon fiber rods are optimal for rod pumping through the build section in pad-drilled wells. This paper will show how carbon fiber rods reduce friction and side-wall loads through wellbore deviations, and enable higher ESP-like rates of production when operated with long stroke beam pumping units.

 

Some Colombian oilfields have medium to heavy oil production and high gas volume in wells.  Gas production is one of the biggest limitations in an ESP system, as they have difficulty handling a high amount of free gas.  In many cases even when an ESP is used in conjunction with a gas separator and gas handlers, the amount of free gas exceeds the capacity of the system and the performance of the pump is not improved.

For a complex well of this oilfield which produced 2.2 MMCF/D (represented around 20% of the total gas produce in this Oilfield). (OSI) designed a double stage gas separation system.  The ESP design consisted of a vortex ESP gas separator, gas handler, shrouded ESP + downhole gas separator with the intake installed below the shroud.  This combination proved to be successful with strong pump performance.