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.

If no pump action, a recommended practice is to shoot a fluid level down the casing annulus and also shoot a fluid level down the tubing.   Distance down the tubing is determined by using the average acoustic velocity obtained from the casing shot.  DO NOT use the tubing average joint length to interpret the down tubing fluid level, because inside the tubing rod couplings are spaced at the length of the sucker rods.

Analysis of the acquired data can determine such things as: If there is a hole in the tubing.  Additional tubing back-pressure maybe required if tubing liquid was unloaded by significant amount of gas produced up the tubing.  Tubing pressure buildup measurement determines the amount of gas flowing up the tubing, tubing percent liquid, and the effectiveness of the dowhole gas separation. Difficult to interpret tubing shots may indicate that the well has “paraffined-up”.  Tubing shots acquired at uniform time intervals can show ineffective pump operation, where “pumping up” the tubing occurs too slowly. Down tubing fluid levels are effective tools when troubleshooting shooting a shut-in sucker rod pumped well suspected of having no pump action.

Available sucker-rod strong design models calculate rod taper lengths that ensure proper operation without premature fatigue failures. Their common design problems are (a) defining the principle of taper length determination, and (b) calculating the true mechanical stresses along the string. The universally accepted principle of taper length calculations is to province the same level of safety against fatigue failure in each taper section. Mechanical loads and stresses, not he other hand, are found form highly approximate calculations in most of the design procedures. These loads, therefore, can greatly deviate from the true mechanical loads that would be measured in the rod string run in the well. The paper discusses the development of a novel procedure that estimates rods loads from the predictive solution of the damped wave equation when designing the rod string. Since loads calculated that way very accurately imitate actual loads the most important limitation of previous rod string design procedures is eliminated. Strings designed using the proposed model, therefore, have a much enhanced safety against fatigue failures as compared to previous designs.

In hydraulic fracturing operations, a large fleet of equipment is required to blend and pump fluid down a wellbore to fracture a formation. High horsepower diesel pumps create the force needed to induce fractures within the wellbore, and in the process, can consume 6,000-8,000 gallons of diesel fuel each day.

In an effort to reduce this consumption, Baker Hughes recently introduced the Rhino biofuel hydraulic fracturing pump which allows for up to 65% replacement if its diesel consumption with natural gas during pumping operations. Biofuel systems present several significant advantages such as no loss of horsepower, improved emissions, reduced diesel consumption, and the utilization of natural gas as a fuel without utilizing a spark-ignited natural gas engine.

With more stringent emission requirements being set forth by the Environmental Protection Agency, it is beneficial to have the ability to reduce operating costs and engine emissions by using cheaper, cleaner natural gas.

As of January 5, 2014, all planned maintenance start-up and shutdown (SMSS) must be accounted for and permitted. TCEQ has also had an effective policy change in what is regarded as MSS and may now consider events related to MSS as Alternative Operating Scenarios (AOS). This paper explores the difference in planned vs. unplanned MSS, when it needs to be reported, when and where it must be reported to, and how to properly plan for complying with the regulatory requirements regarding MSS and associated concerns.

When installed in the liquid leg of the separator, Vortex Tools spin and entrain harmful hydrocarbon vapors from the gas, thereby increasing the oil recovery. By doing so, operators remaining compliance with EPA air quality emissions while recovering additional oil condensate and natural gas liquid values (NGLs). Increased oil recovery, reducing BS&W and cheaper gas are the results of this patented process.

Tested in E Texas wells at 103-degree F ambient daytime temperatures, all production tanks were in air compliance with Vortex (especially important as the number of wells-per-pad has increased while air quality standards remain the same). These patented Vortex tools use no additional energy source, have no additional carbon footprint, and no moving parts/maintenance.

Vortex Tools presented at the 2012 SWPSC on its application for recovering 1 time more natural has liquids than pigging.

A new federal air quality rule governing midstream and upstream activity is in effect.  The rule, also known by its more formal citation 40 CFR Part 60 Subpart OOOO, or ‘New Source Performance Standards (NSPS) Subpart Quad O’ contains new regulations and revisions to existing statutes. This rule will have a major impact on how the Oil and Gas industry has been operating regarding waste gas emissions.  Reverberations will be felt across the industry by these more stringent rules governing upstream exploration and production segment as well as the midstream segment. The rule addresses fracking, compressors and production emissions but the largest source of waste emissions will be generated by storage vessels.  According to World Oil’s estimate of  producing wells, based on surveys of state agencies and company sources, indicates there are over 536,000 oil producing wells and 485,000 gas producing  wells. A very conservative estimate would be about approximately 650,000 crude oil, produced water and condensate storage tanks in the United States and is increasing. Any new Oil and Gas storage tank will be regulated by NSPS Quad O if emissions of VOC’s are more than 6 tons per year. According to the regulation they must reduce emission by 95% through recovery or combustion to be in compliance. Change is in the air.