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.

The performance of downhole gas separators is simulated in software.  Different production rates, different sizes of separators, different SPM and different gas bubble rise velocities are simulated to show the performance of different separators and different well conditions.  This simulation software is a great aid in educating personnel in the operation, performance, selection and proper design of gas separators.  Knowledge and use of this software will help operators increase pump fillage and total production and also reduce operating expenses.

Sucker rod pin and coupling failures continue to plague the oil and gas industry and escalate lifting costs.  The rod connection is solidly designed and is up to the task of staying together if it is properly treated in the field.  Clearly, all paths to the root causes of the premature connection failures lead to field techniques, practices and to unrecognized and uncontrollable variances.  The useful life of a sucker rod is clearly dependent in part, to how it is handled in the field.

This paper will present datasets gathered from the recently developed CDDs (Circumferential Displacement Device) to illustrate "the life" of the sucker rod connection from its initial first make up to point where permanent deformation might call for the retirement of the rod and or coupling.

Hydraulic tubing anchors have been around for over 30 years, however the technology has greatly improved in recent years. To better understand the dynamics of hydraulic anchors, a test rig was constructed to approximate downhole conditions in terms of depth and holding capacity. The test assembly allows for controlling the perceived depth by way of pressurizing the tubing, or internal bore of the hydraulic anchor.  Varying the pressure in the "tubing" simulates the pressures seen at any depth. The holding capacity of the anchor is tested by a hydraulic jack placed under the anchor. The jack, having know bore can easily correlate PSI to lifting force placed on the eh anchor. Numerous tests were conducted at varying depths to find the lifting force required to dislodge, or cause the anchor to slip. Anchor test data as well as analysis of the interface between the anchor and casing will be presented.

The definition of as Gas Locked Pump is both traveling and standing valves remain closed during the entire stroke.  Gas Lock of a sucker rod pump occurs if the tubing pressure on top of the plunger is always greater than the pressure inside the pump chamber and if the pump chamber pressure is always greater than he wellbore pressure on the outside at the pump intake.  The traveling and standing valve open if pressure below the valve is greater than the pressure above the valve.

High compression pumps, specialty pumps, tagging, and slippage through pump clearances cause the chamber into the tubing.  Operators stating "my pump is gas locked" usually have pumped too much gas into the tubing, resulting in unloading all tubing fluids.  Pump action has ceased and the classic dynamometer card "Gas Lock" shape of a gas locked pump is not observed.

The production of the shale oil well at start up can produce high fluid rates with a high energy causing it flow naturally. After this stage, a high rate artificial lift systems such as ESP or Gas lift is required. But because of the rapid depletion of the stimulated zone during the first year (between 60 – 80% in Eagle Ford), the most flexible form of artificial lift available is used, the beam pumping.

Because the pump depth could reach between 4000 up to 12000 ft., the beam pumping system is limited in flow rate.  A big surface pumping unit and high strength rod are necessary. Other complex challenges to overcome are the combination of crooked or highly deviated well bore, high GOR, propant or sand flow back and the presence of H2S. Small tubing completions in shale wells, with 2 3/8” tubing installations, pushes the system to provide high fluid velocity with effective solids transportation in low rates and more inexpensive equipment but with sucker rod diameter restriction to 7/8” slimhole couplings.

Optimizing artficial lift equipment selection , sizing and design with ensure longevity of the equipment and continued production. A premiun sucker rod connection has a design that allows the use of 7/8" and 3/4" strings tapers with KD material to work in corrosive environments with regular size pumping units and lighter strings with guide when neccessary in wells where 1" and high stregth rods should be the conventional alternative.

This paper explains the experiences of more the 70 strings installed and the benefits achieved for a major operator working in the Eagle Ford formation.

Rod Pumping New Drills--sands issues then gas issues-a discussion of rod pump designs for these wells.  As a new wells are brought on many times a great deal of sand is coming back through the rod pump. The pump may also experience gas interference then or later on as the fluid level has been down down.  This paper will discuss many different rod pump designs and why they would be an effective design, a possible design, or a poor design for sand and gas producing new drills.