When operating rod pumps, it is important to match the volume displaced by the pump to the inflow from the reservoir. By doing so, downhole pressure is minimized, thus maximizing production, while keeping mechanical damage and power consumption to a minimum. Various devices such as time clocks, pump-off controllers or variable frequency drives have been adopted in the industry to achieve this goal. While they operate based on different principles and might be suitable for different types of assets, all of them seek to curtail the volume displaced by the pump to achieve pump off while avoiding fluid pound. 

However, the precise tuning of these devices can be challenging and a lot of setpoint management is often done on a customary basis rather than from rigorous analysis. For wells exhibiting simple pump-off situations, this is adequate as the entire production can be realized at near optimal pump fillage. However, many wells (for instance modern horizontal ones with long laterals) exhibit more complex flow patterns, effectively implying a tradeoff between maximizing production and avoiding damaging pumping conditions. When this happens, the optimal operating regime will depend on the precise quantification of the trade-off, commodity prices and the specific circumstances of each well. 

In this presentation, we present empirical data showing that such instances are not mere anomalies, but in fact frequent cases. Furthermore, we introduce novels approaches in terms of data collection and control algorithms allowing us to quantify those trade-offs and maximize well production. 

Much work has been done on the operation of beam pump pump-off controllers, but the downtime is normally a simple timer and the optimum downtime is usually set by rule of thumb or trial and error. This paper uses a complete well model coupled with a transient reservoir  model to show that the optimum downtime in terms of total energy used per produced barrel of oil is equal to the wellbore storage time from well test analysis.

In today’s world it can be challenging to locate the downhole well location immediately below the surface location in secondary and tertiary projects. There are several factors that must be considered when picking the surface location that will maximize value including 1) increases cost of building a location and drilling, 2) increases cost of artificial lift and operations, and 3) production rate and reserve impact.  This paper will explore how these factors can be put in an Excel Spread Sheet to assist in picking the location that will maximize value. 

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.

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.

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.    

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?

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.

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.
 

Lessons Learned with Jet Pumps in a Low Pressure Gassy and Sandy Reservoir with High Deviation The jet pump is said to be a flexible tool adaptable to produce where other artificial lift methods have shortcomings: however, it too requires special considerations in search of economics and life cycle optimization. This report reviews design and equipment upgrades to the jet pump system with solutions and continued shortcomings after one year of operation. The mature low pressure gassy and sandy reservoir located in a remote jungle has been using jet pumps since it was first developed in the 70’s because the field lacks the infrastructure to make rig workovers feasible. The feature of the jet pump most valued in this field is its ability of downhole pump recovery by reverse circulation. Jet pumps were first introduced after development of the full hydraulic piston pump product line and many jet pumps were adapted to equipment designed for positive displacement downhole pumps. Manufacturing and engineered solutions were affected by the late 80’s oil glut, almost wiping out hydraulic lift and completely eliminated the hydraulic piston pump. Fields that need features of the jet pump persist in finding solutions to shortcomings in the same way that solutions are found for other lift methods. The major advantages of the jet pump include its reverse circulation retrieval, tolerance to sand and gas as well adaptability to existing completion for well testing or flexibility in lift capacity. Two other advantages important to the field referenced in this report is the range of deviation that a jet pump can accept and the economics in multiple well pads. Limitations have been attributed to a lack of understanding of the efficiency in energy transfer in low pressure and gassy mediums. Lessons learned in this case history can prove useful in other fields with similar characteristics. 
 

The balance-ported valve is a gas-lift valve that allows full, available gas injection pressure to be used for the unloading and operating valves.  Using full injection pressure allows for a deeper point of gas injection, which lowers the FBHP, thereby increasing total production.  With standard IPO valves, it is necessary to design the valves with casing pressure drops in order to close the valves as the injection point moves deeper.  The balance-ported valve is configured such that no design casing pressure drops are required for closing.  The pilot valve can be utilized later in the life of the well, once the injection point is at the bottom valve and the well is producing less than 150 BFPD.  The pilot valve controls injection into the well in self-intermitting cycles, allowing the well to feed in between these cycles. This allows for lower gas injection rates and increased production.

Contemporary lift strategy for a newly completed well generally includes a period of unassisted flow followed by an Electrical Submersible Pump (ESP) system - up to half a dozen in certain situations. This is followed by one of a multitude of artificial lift options often culminating in a rod lift strategy for low-production to end of life. Ignoring entirely the financial component of these decisions, among the primary drivers of lift type selection is maximum uplift capability – an area in which rod lift has seen significant investment and improvement in recent years. Additional considerations include, but are not limited to, well-bore characteristics, equipment capability, and reliability.

This paper will seek to submit for consideration an alternative strategy for high-volume artificial lift made possible by recent improvements to what has historically been a popular, albeit marginal, lift type: reciprocating rod lift.
 

In unconventional wells unstable dynamic behavior ensuing from an exchange of energy in the casing and tubing is the biggest challenge in gas lift design. As reservoir and tubing pressures decline from early conditions, wells show erratic behavior in decreasing fluid levels and hence unload and operate at variable depths. This case study presents the full workflow of creating an effective gas-lift design from concept initiation to execution and field installation. Successful spacing in gas lift valves for an available gas injection pressure, assures unloading from the deepest point of the tubing string (i.e., packer depth). The design should provide the number of valves for the available kickoff pressure and accommodate future reservoir decline. Two equations provide this flexibility, one for the first gas lift valve (from surface) and another for all deeper unloading valves. After performing a well delivery simulation with a nodal analysis program, a production rate versus injection gas curve is generated at each of the several potential depths of injection. Production rate and corresponding injection gas rate are selected at each depth. The rate from each depth is validated with measured data for outflow and reservoir inflow. Several designs are often needed so spacing criteria, and available kickoff pressure reach the desired injection depth and match the target production rate. This iterative methodology develops the gas lift spacing design allowing for a valve at a shallower depth to ensure unloading efficiency throughout the range of conditions and a valve just a joint above the packer to make production achievable at the lowest possible reservoir pressure. 
 

With the proliferation of production from multiple zones within wells, a major challenge long recognized by industry is to understand which zones are contributing, and how much. This is even more of a challenge with multiphase flow from different zones and with the advent of hydraulic fracturing, correctly identifying which zones have the potential to contribute is critical for future operations. 

A new solution to this problem is to use a jet pump in combination with inflatable packers and a new PLT that uses Patent Pending Doppler sensors rather than spinners to measure flow. This allows the in-flow to be accurately measured while the zone is isolated, with the added benefit of being able to draw the pressure down to assess the potential of the zone when on lift. 

This paper discusses the application of this new method of production logging in a vertical well in West Texas. It will also show the logs obtained in the test well. 

It is recognized in the industry that it is wise to have AL in place before liquid loading is expected for a number of reasons.  These reasons include no production loss when the well drops below critical, convenience as the rig may/may not be available when the well drops below critical later, and in some cases some uplift is observed when installing plunger other AL before the rate drops below a calculated predicted critical. The discussion here concerns installing plunger lift in deviated wells in advance of predictions from well-known methods that say the well is not liquid loaded. However loading and significant uplifts in production are still observed with plunger contrary to what should be expected from commonly used industry indictors.  Some explanations are offered concerning the cases. The results should be of interest to operators that may experience the same situation/s.
 

Vortex Tools addresses the challenges of managing/optimizing hydrocarbon liquids recovery from horizontal wells with long laterals, thereby increasing their economic value. A 2014 five-well case study with a regional independent found that deploying Vortex downhole DX-I tubing tools (in conjunction with gas lift and plunger) saw beneficial increases in oil & gas production, along with a significant increase in water removal, in horizontal and deviated wells. Injection gas rates were also reduced after Vortex was added, but saw increased gas to sales, as well as lower/smoother tubing and casing pressures. Vortex was deployed at the end of tubing, in the horizontal/lateral portion of the well (~80° of deviation). With Vortex tools installed, oil production increased significantly. In one reported case, the oil production increased from 80 barrels to over 400 barrels per day. A two-year lookback on these wells also showed a beneficial decline curve in all cases.