Downhole dynamometer cards can be generated by predictive and diagnostic wave computer programs. Those generated by the diagnostic program are best for trouble shooting as they are calculated from a measured surface card. Several aspects of the bottom cards are presented in discussed in this paper some of which are well known and used and some which are less recognized.

For cards showing gas fill, the location of the TV closing is not the location in the downhole stroke where liquid fill begins. However it is close for low pressure wells. The shape of the load release can indicate if the well has low or high intake pressure. The pump load is indicated if the card is scaled correctly and generated by approximately correct damping or drag coefficients along the rod. A delayed opening of the SV on the upstroke can indicate that the pump is not tightly spaced. The load release distance is incorrectly identified as an area where compression is occurring but this does not indicate compression in the rod above the pump but is where gas, is present, is being compressed below the TV and above the SV. Example are shown of the above.

If looking at only the downhole card, excursions below where the load pick-up began indicate a compression load in the rod above the pump. However high damping coefficients will reduce the apparent fluid load shown on the bottom hole dynamometer and will  also reduce the amount the bottom card may be showing apparent rod compression at the pump so the damping coefficients have an effect on apparent compression at the bottom hole card and these effects are illustrated. The shape of the bottom card can suggest if the damping coefficients are low or high. In general the predictive programs do not indicate compression at the pump unless pump resistance is guessed by the user but the bottom cards can indicate compression but the magnitude of indicated compression also depends on input for the diagnostic computer program.

Both the predictive and diagnostic programs can, under certain circumstance, indicate compression uphole from the pump due to dynamic effects. This can occur even with no pump resistance or rod compression at the pump.  Rod failure characteristics can show if the rod broke after repeated compression (pump resistance) but this is after the fact.

These factors and more are discussed and illustrated to hopefully make problem recognition easier for the operator.

Murphy is currently operating 500 beam pumped wells in the unconventional Eagle Ford Shale play in South Texas. There are numerous challenges to beam pumping operations in the Eagle Ford, which included paraffin, corrosion, solids, deviated wellbores, slug flow, and foamy gassy fluid.

One of the challenges, deviated wellbores, led to an increased frequency of failures due to metal to metal contact between the rod coupling and the tubing. The development of a rod guide strategy has significantly reduced the failure frequency of tubing and parted rod couplings due to wear.

The development of the strategy includes data from the failure data base, the use of tubing scanning, the proper placement of the guides and the use of the proper guide material.

Murphy is currently operating 500 beam pumped wells in the unconventional Eagle Ford Shale play in South Texas. There are numerous challenges to beam pumping operations in the Eagle Ford, which included paraffin, corrosion, solids, deviated wellbores, slug flow, and foamy gassy fluid. 

One of the challenges, foamy gassy fluid, led to a study of the effectiveness of downhole separators. The results of the case study will be presented along with conclusions on the ability to manage or mitigate gas interference in the beamed pumped wells Murphy operates in the Eagle Ford Shale asset.

RFG Petro Systems’ provides custom wireless and digital serial number tags for use within the well-bore infor and attached to the rod string components to assign its recorded quality control system data (batch mation, pressures, times, temperatures, manufacturing date/conditions) and logistics of the product from creation to end-of-life. RFG’s custom hardware and software package allows for the user to scan a product at any time and retrieve its manufacturing and logistics history, better controlling inventory management and asset tracking. By creating new time/date stamps and specific user-controlled instances within the system during the products use, data can be linked with a time-stamp to track and trace how great a product performs over time. Every instance and data-set taken is provided to the manufacturer for continuous product improvement. RFG can license this patented product, software, use and application to manufacturers leading to greater transparency and enhanced products for industry.

This presentation will provide information about the operational advantages and disadvantages of continuous rods.  By removing the pins and couplings in a deviated well, side loading is distributed across a larger area reducing the severity of wear on the rods and the tubing.  The types of continuous rods will be reviewed and operational data presented to assist others in evaluating their potential use of continuous rods.

The addition of a sliding sleeve door (SSD) to the tubing string, installed between the deepest gas lift mandrel and the annular packer, will allow the deployment of a wireline-set jet pump. The backup jet pump provides a valuable and cost-effective alternative in several potential scenarios: when unloading fracking fluids before beginning gas-lift production, when restoring production after an unpredicted shutdown of the gas-lift compression system, and when the producing water cut becomes higher than expected.

This simple but ingenious dual-purpose completion approach has already proved to solve the problem of unconventional well production load-up during the early production stage of gas lifted systems. The information provided in this paper will help operators plan, design, deploy, and operate a dual-purpose gas lift-jet pump well completion.

Achieving consistent, sustained run life with electrical submersible pumps in the unconventional play of the Permian Basin can be difficult due to a variety of harsh well conditions. More specifically, high free gas rates and abrasives contribute to the majority of well service call outs.  Common operating practices are well established to some positive effect, such as running at lower frequencies to mitigate abrasive wear and loading motors appropriately for efficient operation.  BOPCO operates several wells in the area and looked to further optimize ESP production in order to reduce operating expense and increase profitability.  Working together with Summit ESP, a new set of operational standards for these unconventional wells was developed and initiated using a step-wise approach to analyzing individual well performance and operating parameters, then comparing results across the field as various processes and tools were implemented.  In conjunction with the traditional settings, the team implemented a more robust sensor package including a discharge pressure gauge and tubing and casing transducers that are monitored by a highly trained ESP Well Management Team to assist in all troubleshooting.  Further, new gas handling technologies have proven successful in improving up-time with fewer shutdowns.  This dynamic combination has proven to be more efficient and profitable.

This paper will discuss well applicability for gas lift installations, including identifying the best candidates for lift conversion, reasons for converting including benefits in a capital constrained environment.  We’ll discuss GOR, deviated wells, solids handling, typical production rates, while comparing to other popular lift types’ efficiency and range. 

While particular wells may be good candidates based on the aforementioned criteria, surface considerations also play a pivotal role in gas lift installations.  We’ll discuss infrastructure impact of electric vs gas powered compressors, as operators seek to minimize grid impact of artificial lift.  Field-wide opportunity costs of gas & electric supply, fluid processing considerations at CTBs, and permitting will also be discussed.  Finally, this paper will cover  operating considerations and installed equipment to enable successful operations (metering, control, protection, all-weather reliability, automation/surveillance, safety). 

Operating practices, maintenance, training, and personnel costs are discussed in this final section, as gas lift is only successful with qualified operations personnel.  We’ll compare and contrast gas lift operations to other lift types, and will feature differences in surveillance & troubleshooting.

When a hole in the tubing, HIT, is suspected, then confirm the HIT with a pressure test.  If no fluid is produced to the surface, then the test is performed by shutting down the well and pumping clean treated water into the tubing.  The tubing is usually pressured up to 500 psi(g) and the pressure is held for a time period.  If a hole is present, then the tubing pressure will quickly leak off.  A collar leak can take much longer time to leak off. If fluid is produced to surface, then the typical procedure is to use the sucker rod pump to increase surface pressure by pumping against a closed valve. 

If a sudden drop in production occurs, then a recommended practice is to pressure test the tubing, casing check valve, and tubing back pressure valve.  High speed tubing pressure data acquired in conjunction with a dynamometer test provides the operator with enhanced troubleshooting capability.

Lower lifting cost in the oil field is a never ending task. Over the years, many products from pump off controller to fiberglass rods have been used successfully to lower energy cost and extend the life of the well. MotorWise integrates the latest technologies, to substantially lower lifting costs even more. MotorWise combines two technologies: Soft Start and Power Synchronizing to deliver the precise amount of energy to the pump jack in real time. The technology has been deployed on over 2,000 wells in the Permian Basin. Three years of field data confirm the reduction in kWh and KW. This presentation will explain how MotorWise technology is applied in the oil field, the short and long term benefits and the return on investment math.

Lower lifting cost in the oil field is a never ending task. Over the years, many products from pump off controller to fiberglass rods have been used successfully to lower energy cost and extend the life of the well. MotorWise integrates the latest technologies, to substantially lower lifting costs even more. MotorWise combines two technologies: Soft Start and Power Synchronizing to deliver the precise amount of energy to the pump jack in real time. The technology has been deployed on over 2,000 wells in the Permian Basin. Three years of field data confirm the reduction in kWh and KW. This presentation will explain how MotorWise technology is applied in the oil field, the short and long term benefits and the return on investment math.

There are multiple API Recommended Practices for the care and handling of tubing, sucker rods, and pumps.  Additionally, there have been several papers written in support of these practices and documenting how they reduce downhole failures.  However, in the past few years the field application of these practices has taken a step backwards for multiple reasons.

This paper will present some care and handling issues that have been observed in the field that often times would not be discovered without a good root cause investigation.   Some of these issues are caused by the service rigs, but many are due to a lack of proper equipment and training for not only the rigs but support services as well.  Some recommendations to improve compliance of the recommended practices will also be discussed.

Corrosion is a major issue in our industry and it is hard to predict its behavior. It depends on many factors, among which the most relevant are pressure, temperature, concentration, water, PH, chlorines and flow conditions. From the materials point of view, the most relevant parameters are the alloys (such as No, Cr, NB, MO,C), structure, UTS/YS, electronegativity, hardness and toughness. Some alloys give the steel structure certain properties, which are not only related to its mechanical properties but also to grain size, arrangements and molecular interspaces.

As the volumes of injection water/gas rise for mature fields and shale operations also increases the risk of failures related to corrosion processes. TENARIS makes an efforts to evaluate the behavior of standard materials in aggressive environments looking for stronger steels and connections.

This paper aims to discuss the behavior of different Sucker Rods steels in corrosion and the influence of manufacturing techniques.

Technology has developed to integrate pump off control with variable speed drives to capture the secondary benefits of reducing equipment loads and increasing production through continuous drawdown. This paper will discuss the reservoir engineering factors that may limit the effectiveness of this technology trend.  In addition, this paper will address some of operating costs that are often overlooked when attempts are made to continuously  draw down producing reservoir pressures.  For stripper wells in particular, there are a large number of wells that continuous drawdown strategies are not cost effective compared with conventional pump off control shut down schedules. This discussion will allow artificial lift professionals to make more informed decisions about operating Their wells in a more cost effective manner.

Theoretically, each Sharp Edged Seat has fully open stem travel based on the port and ball diameters. Gas lift valve 1.5” has 6 different port diameters (3/16”, ¼”, 5/16”, 3/8”, 7/16” and ½”). For each port the ball diameter is usually larger than the port diameter by 1/16”.

Laboratory testing for sharp edged seats showed that the actual flow area is less than theoretically calculated area resulting from the bellows stacking before the stem reaches the fully open.

            Consequently, the valve stem restricts the flow and the flow rate through the valve declines.

The purpose of this work is to examine the possibility of improving the efficiency of the gas lift valve by using larger ball size than conventionally used.

For each port, different ball sizes were tested at different stem positions for the same condition (Injection pressure & Temperature). Results obtained from benchmark test displayed increasing in the flow rate as the ball size increases at the same stem travel.

Mathematical rod pump models are used in the design and optimization of lift systems. Most models are based on the damped wave equation, assuming steady state cyclic behavior and empirical damping factors. Such models cannot be used for fully transient analyses.

This paper extends the rod pump model based on fluid flow into he reservoir, wellbore and tubing. Rod drag is determined from multiphase flow modeling using the full momentum, mass and energy balance equations with friction loss terms based on standard pipe flow correlations. The effect of transient reservoir flow is incorporated by a radial flow reservoir model for inflow to the wellbore.

Development of the model is discussed and shown to predict complex system behavior. The model is then used to evaluate damping factor and suggest the potential for additional surveillance methods based on transient fluid and rod behavior.

The Wolfberry offers additional production opportunities as well as many operational downhole challenges.  This paper will cover a field study of "gas interference" challenges and the problems of free gas" at the pump. Gas interference creates costly expenditures for operators of Wolfberry and other oil wells with similar wellbore conditions. Poor volumetric pump efficiency, gas pound, gas locking potential, higher energy lifting costs and uncontrollable well operations are some of the conditions to be addressed with some of the downhole gas separator's available today.

Pump spacing on fiberglass sucker rods is very important to the performance of the well and fiberglass rods.  As gas becomes more of  a problem in pumps, the gas compression ratio is even more important.  Edge Production Equipment has developed a chart for pump spacing that will help space wells more efficiently and increase the gas compression ratio.

The Modified Goodman Diagram (MGD) has been used since the 1960s to establish allowable loads and stresses that should be applied to API grade sucker rods.  A previous review of factors that affected the fatigue response for sucker rods has been published.  This work showed that very conservative nature of the MGD for fatigue performance of rods and prompted that much higher allowable loads/stresses could be applied without causing increases in field failures.  This paper will discuss the prior publications and combine the responses from current fatigue testing to recommend a higher allowable loading for the industry using the tensile strength divided by 2.8 versus the prior MDG using the tensile strength divided by 4.0.

While sucker rod lifting is still the method with the greatest number of installations around the world, the terminology and slang that has developed may not contribute the fully understand what is happening to the lift system and especially what is happening downhole.  Without the most appropriate understanding, incorrect diagnoses, troubleshooting, and recommendations to correctly fix problems may not occur. 

This paper will discuss four common terms that are commonly used but normally not used appropriately.  The fist terms hat will be discussed include: fluid pound, stuck pump, rod compression, and rod buckling

There are many oil and gas fields across the United States which have been producing for over 100 years or more.  The barriers that exist to prevent such extended field life are many. Those issues include: rod and rod pump failures, damage to the tubing, paraffin/ scale deposition and corrosion.  All of these can present challenges of how to deal with the problem and correct it, while maintaining economic visibility of a field.

Tackling these issues has mostly been done using batch treatments with various preventative chemicals which over the years have proved to be expensive and not very effective as it cannot pinpoint the problem directly.  More recently the use of capillary injection strings attached to the outside of the production tubing has helped to improve this situation by providing a means of injecting smaller volumes of chemical closer to the source of the problem.  However, on rod pump wells the point of injection can only be made above the tubing anchor; thus failing to protect the pump and internals of the tubing string. A new design of tubing anchor is now becoming available which incorporates a pass through capability for a capillary injection string thus enabling chemical treatment capabilities for the pump as well as the rods and tubing.

Gas interference in a downhole beam pump causes lower liquid production, lower fillage and energy efficiency, possible mechanical damage, and a lighter gradient up the tubing. A gas separator is used to divert as much gas as possible up the casing and not into the pump. Gas locking has been reported but pump leakage would seem to prevent this in many cases. 

This paper shows how to calculate the following: (1) the total gas before the pump and separator; the total gas is the gas in solution plus free gas; (2) the gas through the pump and produced up the tubing; (3) the pressure gradient up the tubing; (4) the gas up the annulus; this allows one to see how much of the total gas (free and gas in solution) gets into the pump after the separator. The gas up the annulus is due to gas separator and natural separation efficiency.

The results shows how to better estimate the fluid load for a sucker rod pump system design and to see how much of the gas is pumped up the tubing through the pump and how much of the gas is separated to the annulus.

Gas interference in a downhole beam pump causes lower liquid production, lower fillage and energy efficiency, possible mechanical damage, and a lighter gradient up the tubing. A gas separator is used to divert as much gas as possible up the casing and not into the pump. Gas locking has been reported but pump leakage would seem to prevent this in many cases. 

This paper shows how to calculate the following: (1) the total gas before the pump and separator; the total gas is the gas in solution plus free gas; (2) the gas through the pump and produced up the tubing; (3) the pressure gradient up the tubing; (4) the gas up the annulus; this allows one to see how much of the total gas (free and gas in solution) gets into the pump after the separator. The gas up the annulus is due to gas separator and natural separation efficiency.

The results shows how to better estimate the fluid load for a sucker rod pump system design and to see how much of the gas is pumped up the tubing through the pump and how much of the gas is separated to the annulus.

In the past the author has presented several papers on the subject in the title.  This would be a third installment with new material and updated solutions from new technology and experiences.

There are a lot of misconceptions about how Sucker Rod Pumping (SRP) systems work resulting in problems that can then be difficult to resolve due to misunderstanding of how the systems or components function leading to the wrong conclusions of what has occurred.  This paper will  go into some of the questions many people ask about SRP systems and how the basic physics and mechanics of a SRP system function and how they relate to the problems and solutions. Also how the components interact together as well as how changes in either the mechanical parts or the operation of the system can create unsuspected problems and failures.

When a high fluid level exists in a well, a tubing anchor can cause free gas to collect below the tubing anchor and restrict production from the formation and liquid entrance to the pump.  The operator may think that a gaseous liquid column exists from the top of the fluid level down to the pump, when actually, the gaseous liquid column exists from the top of the fluid level down to the tubing anchor, and free gas exists from the tubing anchor down to the pump.  The gas that is collected below the tubing anchor causes back pressure against the formation and restricts production from the well.  The operator may think that liquid is surrounding the pump and gas separator, when in actuality, very little liquid is in the wellbore below the tubing anchor.  Liquid is not available to the pump and gas separator.  The paper has field data that shows very little liquid exists around the pump and gas separator in some wells with high fluid levels having tubing anchors.