Two widely used methods of artificial lift are Electrical Submersible Pumps (ESP) and Sucker Rod Pumps (SRP. Each of these methods frequently require methods to avoid or handle gas for successful operations. Presented here are discussions of methods of gas separation for each method and graphical techniques for prediction of the gas separator performance that will allow the user to better select a workable gas separator system and predict maximum well drawdown with the selected method of lift. 
 

Automation is a crucial element to modern production facilities in the Permian Basin.  However, most facilities engineers lack basic understanding of automation and therefore cannot properly design or implement an automated system.  This paper will discuss automation and instrumentation basics as part of a broad automation philosophy to help readers understand how individual components fit into a complete design.  Individual components (or instruments) will be examined to share what options are available to industry and how they can best be utilized.  An analysis of four common field development scenarios will help facilities engineers grow their knowledge and be better prepared to implement automation into their facilities.
 

One requirement of a Class VI Underground Injection Control permit involves continuous monitoring and reporting of injection pressure. Wells in pilot and commercial scale carbon dioxide (CO2) storage sites are equipped with devices that measure pressure and flow rate during injection operations. Downhole device failures have occured during CO2 injection operations in projects, which prevent bottom hole pressure measurement and require time consuming repairs. A model that can be used to accurately predict bottom hole pressures, based on tubing flow performance, during CO2 injection is warranted. 

This paper uses a two-phase flow model, based on Hagedorn-Brown correlation that uses wellbore parameters and correlated CO2 properties to predict bottom hole pressures during injection. A finite-difference program that uses CO2 density and viscosity, wellhead temperature and pressure, bottom hole temperature, tubing diameter, roughness, well length, and injection rate as input to the model was developed for calculating vertical wellbore pressure changes during injection. Input parameters that have some effect on results are presented and discussed.

The program was applied to field injection data from the Illinois Basin Decatur Project and Industrial Carbon Capture and Sequestration projects to evaluate predicting measured bottom hole pressure data.  The predictions matched measured bottom hole pressure within  (average relative error). 

In the past 10 years, drilling methods have drastically reduced the time it takes to drill wells. This is especially true in today’s unconventional shale market where 20,000 ft wells are being drilled in under 14 days. This increase in drilling rates along with increasing depths and deviations has presented many challenges for the conventional rod lift system, which was designed to last for ten years but are now having issues within the first twenty-four months resulting in substantial increases in workover costs. Below we will review the field test results from a downhole sensor that has been developed and is patent-pending which will measure the forces on the rod system and begin the process of optimizing the life of the rod string through analysis of the downhole forces. An additional benefit is that operators and service companies can now verify the effectiveness of new and existing technologies (rod guides, friction reducers…) in extending the life of the system The downhole sucker sensor can be positioned anywhere in the rodstring and collects measured data for pressure, temperature, torque, tension and compression, velocity and position. Using these measurements, a downhole (actual) Dynacard can be generated to remove the guesswork. These measurements are then used to calculate values for specific gravity, pump fillage and pump intake pressure in order to better understand what is actually happening in today’s unconventional shales. The main objectives are summarized as follows: o Comparing actual Downhole DYNACARD measurements to the Surface and the Predicted Cards o Maximizing reservoir drainage and production optimization o Identifying, isolating and optimizing mechanical issues in problem wells o Measuring the impact of new and existing technologies (such as guides, friction reducers, …) and their effectiveness in extending the service life of the SR system.  Can verify if guides. friction reducers… are adding value and not just cost! 
 

Many sucker rod lifted wells are operating at less than 30% electrical efficiency, because the downhole gas separator installed in the well is inefficient.  Free gas interfering with liquid filling the pump is a major operational problem encountered in producing Sucker Rod Lifted wells.  Gas interference is when free gas at the pump intake enters the pump filling displacement volume with gas in place of liquid, then significant loss in liquid production, reduced drawdown, increased failures and inefficiency occurs.  Installing an incorrectly designed gas separator is the most common problem.  Installing very long separators does not increase separator capacity or efficiency.  Restrictions in the annulus above the pump intake such as tubing anchors result in reduced annular gas flow with gas preferentially entering the pump.  A downhole gas separator has a maximum liquid capacity.  Casing size restricts the maximum size gas separator that can be installed in a well.  The separator used in a well should be designed for the well configuration/conditions.  Gas Separators with high separation efficiency should be used to effectively produce sucker rod lifted wells.

The pump stroke can be longer than the surface stroke when the dynamic motion of the beam pump system adds momentum to the rod string, resulting in the pump stroke length increasing.  The pump stroke can be shorter than the surface stroke when sucker rods stretch to pick up the pump fluid load and other frictional forces.  Rod stretch creates under travel dynamometer card shape.  Pumping fast or high plunger velocities creates over travel cards. 

Pump position in the barrel changes when the pump is not full compared to a stroke when the pump is filled with liquid.  When incomplete pump fillage occurs, the plunger tends to over travels on the down stroke moving deeper into the barrel.  In some cases tagging can occur due to pump spacing, plus increased over travel.  This paper will use field collected dynamometer data to show excessive over-travel can occur on both the upstroke and the down stroke.  
 

Deviated wells have now been the standard form of drilling, increasing well life and production but also creating challenges in the Artificial Lift System, specifically the Reciprocating Rod Lift (RRL). With aggressive drilling deviations rod string guiding becomes a requirement, landing pumps in 45+° zones a normal, and gas mitigation a complete necessity to achieve target productions. 

In 2018, An operator in the MidCon introduced RRL systems to their wells; these (7,000ft) deviated wells utilize conventional pumping units (640 / 912 / 1280’s) and mid-strength sucker rods as the rod of choice. Since then several failures have been observed in the pump, tubing and most frequently in the sucker rod string which have been fatigue related with corrosion and compression as attributing factors to the break.

Over the past 3 years, the Weatherford team has worked together to optimize the well designs based on past failure history observed. This paper will discuss the challenges observed, actions taken, and positive results which have minimized the failure frequencies significantly.   
 

Corrosion fatigue (CF) is an important concern for structures that are exposed to cyclic loads in corrosive environments, especially in the case of oil and gas operations like drilling, offshore risers or sucker rods in artificial lift. Considering the current combination of complex wells completions and the increase of water cuts, the CO2, H2S and Bacteria represent a higher risk for CF failures in sucker rods. This combined effect force operators to choose a steel for either corrosive environments or high loads and increase the chemical inhibition programs.

In response to the new downhole challenges, a research and development program (R&D) has been created to analyze the key factors that affect sucker rods performance under CF. As a result of this R&D program, a new corrosion-fatigue resistance sucker rod has been developed. The present paper summarizes the development process, the new sucker rod characteristics and its performance.

Longer laterals, better perforations and larger frac jobs have all enabled increased production capabilities, yet production optimization practices have remained stagnant and, in doing so, limit the ability to draw wells down more aggressively. The data provided in the most common fluid level processes does not meet the challenges generated by fluctuating well dynamics and conditions. The irregularity and inconsistency of current fluid level measurement systems provide an incomplete snapshot of the well conditions when a more complete solution is needed for optimization. With a permanent, automated fluid level system, reservoir and fluid data is continuously attained. By utilizing a permanent, automated fluid level system located at the well head, the frequency of casing pressure buildups, acoustic velocity shots and fluid level shots data can be drastically increased. Doing so allows for more accuracy in data for pump intake pressure, produced gas up casing, fluid gradient and gas-free fluid levels on rod pumped wells. Paired with properly-tuned algorithms and current optimization practices, these data points give a clearer and more complete story of what rod pumped wells experience continuously throughout the day. Additionally, more information about the reservoir is produced than previously available. This paper aims to introduce the GreenShot, how it works, and what it provides to the operator as well as present case study results that show the production improvements supplied utilizing GreenShot while depicting robustness and accuracy. 
 

The most common well profiles for reciprocating rod lift applications are deviated and highly corrosive wells. Many newly drilled horizontal wells exhibit moderate to severe deviations which require the pump to be set in the curve to produce intended target zones; resulting in a challenging environment for rod lift systems to successfully operate. These wells tend to be accompanied by corrosion, furthering the possibility of premature failures on all downhole equipment: rods, tubing, and pumps. 

Several companies have worked to find a solution to these problems, with one simple product seemingly leading the way, continuous rod. In many wells such as these, continuous rod has proven time and time again that it can improve run life, reduce failures, and optimize production. Continuous rod has recently gone one step further by adding an epoxy coating to resolve the corrosion problem. Several wells have been field trialed and have shown great improvements. This paper will provide an overview of the technology and the field improvements observed up to now.
 

This paper will discuss reducing failures in rod pumped wells by using best practices and design changes. The theme of the paper is to share solutions observed over the last 41 years while working with rod pumped wells. These best practices applied from the polished rod through the bottom hole assembly have been proven to improve run time between failures. The topics discussed are improper installation of equipment along with the effect of a properly designed bottom hole assembly. I will also highlight pump designs and accessory items to help with sand and gas issues. When you lower your failure frequency you are reducing exposure to potential accidents benefiting us all.

Production challenges in horizontal wells are caused by slug flow behaviour from the horizontal. In response, Production Plus developed the flow conditioning HEAL System to mitigate slug flow before fluids enter the downhole separator and pump. Slug flow mitigation allows rod pumping to be more effective and efficient, offering a solution for low-cost OPEX to reliably maximize drawdown.

This paper analyzes multiple HEAL System installations in the Permian Basin that transition from gas lifting to HEAL System rod pumping. It explores requirements for intermediate artificial lift systems, challenges achieving production forecasts, slug flow and solids production mechanisms, and impact from horizontal trajectories.  The discussion compares recent long-term, multiple case studies that statistically demonstrate the impact of flow conditioning on well production economics. It offers insights into long-term NPV benefits achieved by transitioning from gas lifting to the HEAL System with rod pumping.

Evolution of annular gas lift candidates and early results of application in the Delaware Basin. 

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

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

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

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

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

One of the most misunderstood issues in sucker rod pumping is tubing back pressure. The great majority of wells that I have encountered in various fields have back pressure valves installed on the tubing side of a wellhead. However, a great many field personnel do not understand why back pressure is applied, how much to apply, and/or how it affects a well’s performance. This paper will discuss the why, when, and how tubing back pressure is applied along with some misunderstandings and issues of its application. 

Tubing leaks account for half of the failures in the Bakken wells. The root cause is coupling on tubing wear due to the non-metallic guides wearing out.  

In order to combat this problem, ToughMet 3 TS95 sucker rod couplings were installed in up to 250 wells to significantly reduce the failure rate in the field.  Several individual case histories will be discussed to demonstrate the lifetime extension and reduced wear rates seen with the use of the new couplings.

Additional benefits have been observed, particularly increased fluid production, increased pump fillage, higher Fluid loads, and lower gearbox loads. XSPOC data will be presented for several wells to demonstrate the positive effects observed in the field.

Sucker rod pump or “rod pump” is a common method of artificial lift for oil and gas wells in the United States. For decades well analysts and production engineers have looked at surface and downhole dynamometer cards to diagnose various downhole and surface equipment issues alike. In more recent years, helpful rod pump diagnostic tools have aided well analysts and production engineers in training and the analysis of downhole dynamometers utilizing generalized libraries with known behavior for downhole dynamometer cards. Unfortunately, the same generalized libraries do not exist for surface dynamometer cards limiting these tools to base their diagnostics solely on information captured in the downhole dynamometer card. Although a majority of data used for analytics and diagnostics can be found in the downhole dynamometer card, it has been known for years that still more helpful analysis can be done utilizing data and patterns found in the surface dynamometer card. Recently, strides have been made in software tools to analyze data and patterns not only found in downhole dynamometer cards, but also the surface dynamometer card. It has been well known within groups with expertise on dynamometer card analysis that pump tagging and shallow friction can be seen more obviously in the surface dynamometer card than the downhole dynamometer card. Mimicking the thought process of these experts, algorithms leveraging data science tools and statistical methods have been implemented in diagnostic software tools that can better detect both shallow friction and pump tagging problems that can be seen in the surface dynamometer card well before they are seen in the downhole dynamometer card, especially for deep wells. These new algorithms will be yet another tool in the continual aid of well analysts and production engineers to more quickly and effectively analyze dynamometer cards and optimize production for the sucker rod pumping system. Although current downhole analytical software provides great benefits to users, including these algorithms allows for a more robust and effective dynamometer card analysis and diagnostics software.

Gas and sand interference remain one of the most common challenges in the vast majority of wells in the Permian Basin. Gas interference can lead to poor pump efficiency and severe sand issues can lead to sticking and excessive wear and tear to the pump – both of which lead to unnecessary operational expenses and even well failure. Recognizing the ineffectiveness and shortcomings of current models of gas and sand separator systems and other mitigation technologies, WellWorx set out to design a more effective system to combat the dual issues in rod pump wells. In the first stage, fluids enter the sand separator and solids are removed using a dual-channel spiral system before forcing solids into a three-foot sand drain that maximizes the distance between pump intake and solids discharge. In the second stage, the gas separator creates the greatest tool OD to casing ID ratio possible, allowing operators to maximize the annulus of the given well bore. By increasing the size of the annulus, it decreases the downward fluid velocity of the fluid prior to pump entry, allowing gas to escape up the casing. Installing this type of equipment could potentially allow operators to stay in higher production longer and give more freedom in pumping practices with or without lowering the pump in the curve, all of which raise profitability. This paper presents the technology behind this combination gas and sand separation system and offers case study results that proves the positive impact of this tool on overall operating expense.
 

Rod pump service data provides valuable insight into wellbore conditions and the efficacy of the rod lift system. Trend analysis of metrics such as reason for well pull and pump component evaluation provides increased visibility about individual well performance issues and more broadly, about field performance. Comprehensive pump service data is an indispensable supplement to an operator’s internal data in well review meetings for the purpose of improving optimization efforts. This paper will focus primarily on how this data may be used to benefit two key factors: performance and design.

During the hydraulic fracturing age, hydraulic jet pumps have seen an increase of installation numbers across the most prolific unconventional well fields in the United States of America, as well as in overseas oil and gas fields. Its simplicity, reliability, robustness, and adaptability have made the jet pump one of the known artificial lift systems on the production of unconventional wells, specially on the early stage of production. During this stage production rates are high, and solids (proppant) are produced; this can be a challenging combination to deal with. When correctly operated, jet pumps can be a useful and effective solution for this unconventional well production cases. Jet pumps can and it have been used to continue to produce an unconventional well through its producing life to depletion, until a transition to a different method is needed, mainly because of the minimum required pump intake pressure that a jet pump needs to operate. Jet pumps require a minimum suction pressure to function, otherwise a phenomenon called “power fluid cavitation” or “low intake pressure cavitation” will occur. When the down-hole pressure of an unconventional well that is operated with jet pump declines to lower levels, specific operating and optimization strategies have to be implemented, in order to maintain acceptable production rate levels, and to optimized the usage of the available surface equipment capacity. During the late stage of production of an unconventional well , a successfully operated jet pump strategy includes several good practices that include: Well completion configuration, surface equipment selection, suction and discharge piping, production data processing and analysis, nozzle and mixing tube resizing and power fluid pressure schedule. The correct application of the previously mentioned actions, increase the possibilities to approach to a trouble free operation, and to a continuous jet pump system implementation from its installation, on the early production stage, to a point where the well flowing pressure is too low that a change of system is required, to a low rate – low pressure production system. This paper presents a straightforward discussion on the operation of jet pump systems during the late production stage of unconventional wells, recommended practices, troubleshooting and procedures to keep the well producing, even when the pump intake pressures are relatively low. 
 

There are thousands of marginal wells in the Permian Basin with potential to produce significantly more oil and gas with the assistance of plunger lift.  Working with multiple operators in the Permian Basin, PLSI has installed plunger lift systems in these type wells and realized significant increases in oil and gas production.  The common characteristic is fluid downhole which never makes it to the surface production facilities.  This fluid loads up the wellbore downhole which increases hydrostatic back pressure on the formation that holds back production.  By installing a plunger lift system, we have seen wells that were producing a few barrels of fluid per day double oil or gas production. This paper will present production data from operators showing increases in production and revenue with minimum expense that resulted in significant increases in net operating income. 

Deviated wellbores, whether intentional or unintentionally drilled, are becoming ever more common. Rod-on-tubing friction occurs as a result of these wellbore deviations. This friction has a detrimental effect on the longevity of the equipment through accelerated mechanical wear. Downhole friction can also obscure analysis and optimization as the friction distorts the calculated downhole conditions. The only methodology currently available to account for this wellbore friction is through by way of a wellbore deviation survey. Deviation surveys have varying degrees of resolution, from coarse 100+ foot surveys during drilling, to high resolution gyro surveys which can resolve one foot or better along the wellbore length. Geometry derived from the deviation survey is then used to infer points of contact along the sucker rods, and in conjunction with the wave equation methodology, tensile and side loads are determined. These are idealized calculated values because the geometry is indirectly measured, and contact points are not exactly known or understood. The work presented here attempts to directly measure friction along the wellbore. Two fundamentally similar approaches are discussed. The first utilizes an instrumented rod-hook to measure load and position during a workover. Wave equation methods are then applied for each ?stroke? of the rods by the workover rig while pulling rods out of the hole to determine dynamics along the remaining section of rods in the wellbore. A friction map can then be computed over the entire length of the wellbore as rod sections are installed or removed. A second approach utilizes a downhole tool that is run on the sandline or wireline. A section of weight-bars of a desired length below (and possibly above) the tool provides an opportunity for friction to act during the trip out of the hole through the wellbore. Correlating loads measured by the tool with position along the wellbore, and eliminating dynamic forces due to acceleration, provides a directly measured friction map of the wellbore at or near the points of friction. Both approaches require little additional interaction from surface personnel as the work necessary to gather the data is already performed. All that is needed is to capture and process the data from those existing operations.
 

Horizontal drilling and the need for effective completion techniques has given birth to a wide variety of solutions in North American oil and gas plays. For many operators, it has become a top priority to optimize proppant distribution using buoyancy enhancer additives and to achieve fracture diversion with clean solutions that do not require intervention. At the heart of these initiatives is the Permian Basin, which is being revitalized through the use of intelligent completion technologies to make those priorities a reality.

This paper proposes two solutions that can be customized for an integrated fluid system that helps improve proppant distribution, deepen proppant penetration within the complex fracture network, increase proppant pack volume, and increase maximum proppant concentration that can be placed. By improving proppant placement and increasing the fracture volume occupied by proppant, operators can enhance conductivity of the fracture network, resulting in improvements to initial and long-term production.

Unconventional wells are drilled in shale formations to produce oil and gas utilizing horizontal drilling and hydraulic fracturing. Many think fracturing creates a ‘rubble zone’ around the wellbore allowing the free oil and gas to be produced. 

Unconventional wells are generally drilled “vertical” and then “kicked-off”, building the curve and then continuing to drill horizontally at a targeted distance through the layer of oil-bearing rock. Due to the intentional and unintentional dogleg severity that occurs throughout the drilling process, extreme side loading conditions are created when rod pumping.  S curve wells are common unconventional wellbore trajectories that present challenges when rod pumping. 
Due to the rock properties of shale formations, wells with long laterals through the pay zone are completed. This results in large production volumes with exponential decline. As these wells begin to decline, artificial lift is needed to continue to effectively lift fluid to the surface. Rod pumping is usually the preferred artificial lift method for liquid rich wells. 

This paper focuses on the sucker rod string as it delivers the energy created at surface to the downhole pump. The sucker rod string typically consists of steel sucker rods, connected by couplings every 25 feet, to mechanically lift the fluid from the downhole pump. 
Unfortunately, the complex trajectories of unconventional wells create mechanical friction between the rods and tubing resulting in extreme side loading conditions. This leads to rod parts or tubing leaks from extensive wear of the contact area between the couplings/rods and tubing. The force or side load is often concentrated on conventional rod’s couplings, increasing the pressure between the rod and tubing string. This leads to an increase in failure rates.
Continuous rod is a viable solution for deviated wells because of the lack of couplings, the side load is distributed over an increased area of contact. This results in longer run times. 

This paper presents results from five high failure rate wells that were converted from conventional sucker rod to continuous rod due to failures caused by downhole deviation.
 

Failure meetings are a proven optimization tool to reduce failures, cut costs, and increase production. However, many companies don’t utilize this tool or don’t properly optimize it. This paper will cover the basics of preparing for and holding a failure meeting along with a brief explanation of root cause analysis.