Unconventional play drilling and completion are pushing for longer laterals and more aggressive fracturing to maximize reservoir contact. On the other hand, there is no one-size-fits-all solution for artificial lift. This study characterizes artificial lift trends in the Midland and Delaware Basins using a dataset of well completions, production performance, and lift methods. Results show distinct variations in lift selection driven by geological differences, gas-oil ratio, well depth, and lateral length. The Midland Basin is skewed toward ESPs and rod pumps, with lower GOR and shallower depths, while the Delaware Basin presents a higher preponderance of gas lift due to deeper wells and higher GOR. Second, the concept of lift has been in a stage of evolution: from changing reservoir conditions to changes in completion design. Though the dataset does not provide in-depth operational details the observed trends shed light on artificial lift practices, highlighting industry preferences and areas where optimization may be possible.
 

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.  

In sucker rod pumps, accurate downhole data is necessary for control and optimization of wells and assets. Downhole data is calculated from data measured at the surface. 
In the 1990s, Sandia National Laboratory was contracted to conduct a series of tests using downhole dynamometer tools on vertical wells. This data validated the use of the wave equation and gave rise to most of the models and programs used today. In today’s Oil & Gas world, where a great majority of wells are deviated, operators have difficulty controlling and designing their wells due to inaccurate downhole data and key parameters.
This presentation will focus on comparing the conditions and equations relating to vertical and deviated wells. In a first step, the vertical case will be studied, and the wave equation derived. Challenges to using the wave equation and therefore shortcomings of today’s methods will be discussed. In a second step, the deviated case will be explored and compared to the vertical case. 
 

In the reciprocating rod lift system, the sucker rods are subjected to cyclic stresses during service which accumulate leading to fatigue failures. It is well known that the shot peen process increases the fatigue life on metal parts; with respect to sucker rods several manufacturers claim to have implemented shot peening in their manufacturing process for years. To achieve optimal parameters which yield a dramatic increase in fatigue life requires extensive studies on both input parameters and comparative fatigue testing. This paper will discuss the steps and challenges involved in achieving the optimized shot peen process and benefits on the sucker rod fatigue life. Process inputs such as shot size, shot metallurgy, shot velocity, the volume of shot and peening time was studied and evaluated by an axial fatigue test which replicated downhole loading condition. The laboratory test results were also validated with field data to show increased runtime on sucker rods. The laboratory axial fatigue test showed that the optimized shot peen process increased the fatigue life of the sucker rod approximately 37 times as compared to non-shot peened rod. Sucker rod failures relating to fatigue were tracked after the implementation of optimum shot peen parameters into the manufacturing process and the field data showed a decreasing trend in sucker rod failure rates which supports the laboratory results. This paper presents an insight into how an optimized shot peen process can help to improve the sucker rod quality from a fatigue perspective.
 

Review of Field Data To Evaluate Impact on Overall Maintenance Costs when Rod String Spacing Tool/Rod Rotator is implemented with a Wireless POC Load Cell As companies seek to optimize performance of rod pumped wells, they examine common problems which may include improper rod string spacing resulting in rod pump damage, rod failures and cable failures of pump off control (POC) wired load cells. Traditional methods of adjusting rod strings requires removal of rod clamps and exposes field personnel to pinch, fall and struck-by hazards. To mitigate this risk, some E&P companies require a third-party to adjust rod string spacing, resulting in significant expense. This session will explore how using a new tool to fine tune well spacing reduces safety hazard exposure and risk associated with rod string adjustments. It will discuss how precise placement of the rod string impacts rod pump maintenance and well productivity based on a data from E&P companies who have implemented this new well spacing tool/ rod rotator between Dec 2017 – March 2020. Additional findings quantifying the impact of pairing this rod string adjustment tool with new wireless load cell technology on field operations / maintenance costs on installs in 2020 will be discussed. 
 

More efficient operations and lower failure rates will result if sucker rod lifted wells are operated with a pump filled with liquid.  Dynamometer and fluid level surveys can be used to identify when the well is operating properly and when there are operating problems.  There are a variety of recommended practices for operating sucker rod lifted wells to provide low operating cost and low failure rate.  Data will show that long and slow versus short and fast both result in high failure rates when the sucker rod pumping system has incomplete pump fillage.  Frequently inspection of dynamometer data collected on sucker rod lifted wells operated using pump-off controllers, variable speed drives or timers show incomplete pump fillage.  Incomplete pump fillage is often associated with a “pumped-off well” or gas entering the pump replacing liquid fillage. This presentation will show data collected on several wells to address problems created by operating a pump not filled with liquid.
 

Rod pump failure tracking has become a crucial component to any rod pump program in order to maximize run life and more effectively evaluate failure mechanisms. This course will dive into chemically preventable failure causes for rod pump wells highlighting root cause analysis, corrosion/bacteria control, solids management, product selection and program evaluation. 

Most operating areas require chemical programs, but most operating companies do not have chemical knowledgeable personnel to help set a program up, evaluate its performance, and/or optimize the overall program.  This paper presents an overview of chemical programs along with a brief discussion of various potential parts of a program.  An operator will be able to use the information presented here to set up performance indicators to evaluate a program and decide how best to optimize their chemical program.    
 

 Horizontal wells have a tendency to have surges of fluid and gas when producing. Especially in the case of gas, we tend to see gas production flowing in slugs, resulting in intermittent production of liquid and gas. This unpredictability of gas slugs and surges leads to free gas entering the pump more frequently and being harder to control than in a vertical well. This can lead to decreased production, efficiency, and pump fillage. To deal with the issues that surging in horizontal wells can lead too, Odessa Separator has developed the surge valve. The surge valve was designed to help capture the surge above a packer by not allowing the surge fluid to fall back into the horizontal section. Doing this allows for each stroke of the pump to pull more gas free liquid, therefore increasing the pump fillage and the production of the well. This paper presents a case study of a well with high gas production where the surge valve was run in conjunction with a packer type gas separator to help deal with the gas. After the installation of the Packer Type Gas Separator with the Surge Valve, the production and pump fillage both increased by nearly double while also decreasing the GLR. 
 

With the recent proliferation of federal and state regulation in regards to allowable emissions limits from oil and gas production facilities, sound emissions control methods and their utilization have become increasingly more important.  Operator environmental compliance has been frequently emphasized by regulatory agencies, and using vapor combustion units (VCU’s) to limit the atmospheric exposure of volatile organic compounds (VOC’s) from on-site storage tanks is a practice that is seen with increasing regularity. The installation of VCU’s can be time sensitive to ensure regulatory compliance and, because of this, it is not uncommon for the importance of key variables to be underestimated or overlooked.  Throughout this paper, considerations are provided to bring several of these factors to the operators’ attention to ensure that the unit and associated piping is installed with maximum effectiveness.

Downhole separation of gas and solids for sucker rod pumping continues to be a significant challenge, particularly in horizontal wells. An advancement in downhole separation has been achieved by realizing there was an opportunity to intentionally take advantage of transient multiphase flow conditions where liquids and solids flow reversals exist. Multiple case studies in this presentation, demonstrate that taking advantage of multiphase flow reversals can enhance downhole separation performance and capacity, while at the same time lower operational risk. Methods, Procedure, Process Improving downhole separation without undesirably increasing operational risk and cost has been challenging. A separator design that requires a packer or annular seal, such as a cup, is inherently more operationally risky from an installation and retrieval perspective. Further, a separator design that impose pressure drops and/or increase flow turbulence face the risks of scale deposition, erosion, and reduced separation capacity due to turbulence worsening of the amount of entrained gas in the liquid. It is generally understood that separation capacity has been physically limited by a separator’s cross-sectional area for separation. It is less understood that separation capacity has also been limited by the location and orientation of a separator’s intake, and that it has been limited by a common mechanical design practice of a concentric or centralized pump intake dip tube or mandrel. Technical literature, industry research and transient multiphase flow simulations have revealed, under certain conditions, that multiphase flow reversals are not only present, but also occur at high frequencies. In a wellbore, after the onset of a flow reversal and during the liquids accumulation process, parts of the liquid phase in a multiphase fluid stream move upwards concurrently with the gas, and simultaneously, other parts of the liquid phase move counter-currently downward with the gas. In other words, parts of the liquid flow will frequently reverse direction from upward to downward. Counter-current flow reversal experiments observed that as the gas rate continues to decrease this partially-concurrent/partially-counter-current liquids behavior progresses up until the point where the liquid’s hydrostatic pressure gradient becomes zero (hanging liquid film field) and then after that point, the multiphase flow transitions to a fully counter-current liquid flow (i.e., net liquids flow rate is negative) leading to a maximum rate of liquid accumulation downhole. Industry research has also disclosed that gas-liquid separation in an eccentric annulus is more efficient than in a concentric annulus. In addition, such research disclosed separation efficiency is greater an open top tube versus an annulus. Both of these separation efficiency benefits are due to the changes in the slip between various parts of the eccentric cross-section of the multiphase flow field. It was hypothesized that such transient, ongoing, partial flow reversals could be taken advantage of and in combination with the separation benefits of eccentric flow paths, downhole separation of gas and solids could be significantly enhanced in conjunction with lowered operational risks. A separator was then designed, built, extensively flow loop tested and successfully field implemented. Results, Observations, Conclusions This presentation describes the design process and results of the field implementation of an enhanced downhole separator that intentional uses transient multiphase flow reversals and eccentric flow paths. Flow loop testing results and comprehensive analytical transient multiphase flow simulation will be shared. A set of case studies, in multiple basins, reviews the field installations and presents the results of improved downhole separation performance, lowered operational risks, lowered Opex and increased production.
 

This paper will cover the theory of operation of downhole sucker rod pumps, compression ratio calculations, some misconceptions about gas handling, simple special valves and accessories, complex specialty valves, gas breakout in the pump, dual compression and specialty pumps, some successful industry solutions, and other ideas about dealing with gas in downhole sucker rod pumps.  

Vapor Recovery Units are often expensive, complicated to operate and unable to deal with High H2S and liquids.  The Beam Gas Compressor is a product that has served the measure of time.. after 35 years of operation its durability is now being shown as a vapor recovery unit. Without the need of a control panel and scrubber tank the Hydraulically driven Beam Gas Compressor (HyBGC) can be easily serviced by most oil field personnel.  No special schooling or training is necessary.  Without the need for a control panel there is no need for special automation technical service.  Making the HyBGC the perfect VRU for small to medium size companies.  Majors too, anyone needing consistent and reliable emissions control.

In the Permian Basin, new unconventional wells on ESP systems experience production challenges due to high gas to liquid ratio. Unconventional wells having high initial rates with steep declines requires wells to be pumped aggressively early on. ESP’s by nature are designed to pump only liquids. Gas entering the ESP not only decreases volumetric efficiencies, but also causes high temperature issues and erratic run behavior. This decreases production and degrades the mechanical integrity of the ESP, leading to higher maintenance costs and ESP failure. Since ESP failures are one of the major expenses incurred by the operator, the most effective method to reduce OPEX is to increase runtime and decrease ESP failures by reducing the amount of free gas that enters the pump. Operating conditions can be significantly improved by utilizing the innovative technology of the ESP Gas Bypass when paired with proper ESP design and operational practices. The ESP Gas Bypass utilizes a packer to isolate all flow before reaching the pump intake and creates an isolation chamber below the ESP. Pressure is then created so as fluid moves upward, gas is released naturally. The primary focus of the tool is to utilize the casing to create a natural downhole gas separator, which allows trapped gas to be discharged well above the pump intake of the ESP. This paper presents the technology behind the ESP Gas Bypass and offers case study results that proves the positive impact of this tool on overall operating expense.  
 

Advancing technology has enabled the oil and gas Industry to analyze and track constituents in fluid samples. However, without proper sampling, proper laboratory procedures, and the correct interpretation of such analyses, this data could be erroneous and could result in costly and unnecessary actions.  

Through proper analytical sampling, testing and understanding of these results operators can monitor and optimize chemical applications.

This paper discusses:
• Common analytical testing performed within the oil and gas production  
chemical industry.
• Identification of critical hold-points within these procedures.
• Common general rules for the identification of possible anomalies during  
such analyses.
• How these tests can be applied to assist optimization of chemical  
applications.

The advent of low-cost IoT systems powered by AI/ML Algorithms provides new production optimization tools available at the well site to achieve the digital transformation in the onshore oil and gas business. The unique capability of well diagnostic at the edge opens new opportunities from artificial lift to production optimization. The goal is to improve overall efficiency by reducing failures, anticipate deteriorating operating performance by timely introducing mitigation options. To demonstrate the value of the technology we have selected the underprivileged sucker rod pumping wells and developed diagnostic capabilities for these wells. Technology Solution designed and sensors, gateway manufactured in the USA. It gives an opportunity to customize the system for addressing the needs of unconventional, marginal fields, stripper wells. In this talk, early technology solution development and field case studies will be presented.