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. 
 

This research was conducted to solve problems of Super Absorbent Polymers (SAPs) dehydration in oil field applications.  Two polymer sizes were used separately and mixed with various brines.  After allowing the polymers to fully swell, oil was added to the mixture and the effects of Brine was observed.  Initial readings of oil effects on swelling was taken.  The samples were allowed to hear to 100 degrees Celsius and the effects were recorded. Oil increases the hydration of SAP's for both types of polymers.  Also, for both sizes of polymers, high temperatures caused polymers to float.  The heat lessened density of the polymers.  Particle size was a factor in the behavior of the polymers.  These results can identify which particle size to use according to the brine concentrations, temperatures, and the reservoir fluid properties.  Knowing how oil effects the SAP's helps oil companies to create a formula for each circumstance.  

There are a lot of multiphase flow correlations available in oil industry worldwide, but many times these correlations do not match with the real measured pressure data, consequently we need to get out the best correlation for this data which is give us the representative or reliable results close to measured data with the least error as possible as we can.

In our study we took well X-1; from Nakhla Field as a case study. Six production tests were used to estimate well productivity index at different time and flowing pressure survey were collected and analyzed by using Microsoft Excel and PROSPER software in order to calculate and plot the pressure gradient and to compare the results obtained by different methods with the actual one to find the best method that gives us the less value of error comparing with actual one used for construct IPR-VLP performance and make prediction for future performance by using sensitivity analysis for different reservoir pressure and gas oil ratio (GOR).

Based on this study, some of the multiphase correlations given acceptable results if compared with actual data measured ones, but didn’t have any solution in nodal analysis as in case of Mukherjee Brill correlation, and some of them given low value of error but there results and behavior in the nodal analysis not acceptable as in case of Beggs and Brill correlation.

Understanding natural fracture systems plays a key role in tight carbonate fields where production is dependent on secondary porosity and pore connectivity. Locating geographic and stratigraphic areas with high natural fracture density and optimizing horizontal well plans to connect fractures can enhance well performance and asset value. A workflow to identify the influence of natural fractures on well performance was conducted in the stacked carbonate play in east Texas. Density, resistivity, and gamma ray logs were used to generate an index curve to identify natural fractures. In wells with image log data, a reasonable correlation was observed between the fracture zones selected by this model and the image log interpretation. The index curve was calibrated with image log interpretation, and applied in other wells without image logs. Identifying the optimal distance from the fault where fractures are still present has become the main criterion for selecting locations for horizontal wells. 

This paper proposes a new method to deal with sand and chemical problems in the ESP. The protection system consists of 1) ESP sand separation system that works in two stages assuring the best sand separation efficiency. The first separation stage is composed of a V-wire geometry screened designed based on production. The second stage is a centrifugal system formed by a sand cutting resistance sleeve and a helix that creates a Vortex Effect. 2) Chemical treatment in downhole that microencapsulates the original components used on the surface and allows their installation and controlled dispersion at downhole below the sand separation system. The new system for sand control and downhole chemical treatment was successfully installed in 70 wells in one year. The design considered factor as the production expected, particle size distribution, mechanical well conditions and complete water analysis of the wells.  This paper summarizes the most relevant cases.
 

Reservoirs having clays that swell/migrate can potentially impair production. When these clays are present, it is advantageous to use clay stabilizers to mitigate this damage potential.  The industry has adopted several clay assessment methods including analytical procedures such as XRD, SEM and performance testing methods such as capillary suction test (CST) and roller oven test. This paper will describe a new performance test method for inhibitors used in shale reservoirs that complements the existing methods.  A modified core flow method has been developed using unconsolidated core material that indirectly measures the clay swelling and migration potential.  In this procedure, a packed column composed of tightly-sized shale material is used to simulate an infinite fracture network.  Treatment fluids are then pumped through the column at constant rate while measuring pressure drop.   The relative pressure change, together with the turbidity of the effluent, allows easy assessment of the clay stabilizer.

The issues of leakage with respect to the clearance between the pump plunger outer diameter (OD) and the pump barrel inner diameter (ID) and other operation conditions have been revisited in this paper using viscoelastic models. Both Poiseuille flow rate due to the pressure difference and Couette flow rate due to the plunger motion have been considered. The purpose of this study is to better understand the nature of the leakage with respect to pressure difference, eccentricity, and motion related to the plunger of typical sucker rod pump systems and gradually to link the downhole dynamics and motions with the surface pump jack unit. More specifically, based on the newly derived relaxation time scales for transient solutions of the governing Navier-Stokes equations, the quasi-static nature of relevant measurement techniques is confirmed for current production systems. 
 

Rod pumping unconventional wells can be challenging due to increased side loading conditions thru the curve section of the wellbore.  Likewise, ‘S’ shaped wells and unintentional dog legs present a similar problem with increased failure rates.  All of these conditions lead to higher side loading resulting in increased friction and wear and a corresponding decrease in Mean Time Between Failures (MTBF). This phenomenon can make lifting fluids with rod pumps problematic due to extreme deviations and the resulting forces.

As production and bottom hole pressures decline, many wells will be converted to rod pump at some point in their lives. Rod pumping is usually the preferred artificial lift method for lower gas to liquid ratio (GLR) wells with low or declining bottom hole pressure.   When unconventional wells are converted to rod pump, they usually start out with the pump set above the kick-off point.  However, as production declines, the operator may need to lower the pump to maintain economical production rates and maximize hydrocarbon recovery. To achieve these goals, operators have pumped the curve with varying levels of success. Historically, when lowering the pump into the curve, failure rates increase due to increased mechanical friction on the downhole equipment. Tubing leaks, rod parts and pump failures are the most common failure types for these applications. 

When pumping through the curve, rod guides are often installed on sucker rods below kick off point as they provide a sacrificial wear devise that attempts to protect the tubing and rods.  Unfortunately, rod guides increase the amount of friction in the system. 
Thermoplastic liners, which are mechanically bonded to new or used tubing, significantly increase run time by preventing rod on tubing contact. Installing thermoplastic liners below kick off point can decrease failure rates by reducing the downhole mechanical friction. 

The effects of different corrective measures to deviation and their respective coefficients of friction are detailed and discussed in this paper.
This paper presents results from a case study where thermoplastic liners were installed on high failure rate ESP wells that were converted to rod pump and provides evidence that pumping the curve can be an economical and feasible option for operators when designed properly.
 

This paper discusses Permian Basin examples of a modern epoxy resin system that is compatible with most water- and oil-based wellbore fluid systems. Its unique mechanical properties and resistance to contamination make it a good solution for issues too complex, costly, or difficult to resolve using traditional remediation methods and materials. These case studies include the following uses of this epoxy resin: 1) as a squeeze treatment to repair a well production casing leakage, re-establishing casing integrity, and allowing the planned stimulation treatment in 60 stages; 2) on a rigless intervention to spot a cap on a sand plug to abandon a set of perforations and help improve the injectivity profile in two wells; 3) during gas-tight re-cementing operations through casing perforations after poor primary cementing; and 4) during remediation of tight casing leaks in injection wells to meet mechanical integrity test regulations.

The prevention and mitigation of paraffin and asphaltene deposition in oil and gas wells behaves differently depending on each well’s fluid chemistry and the thermodynamic production conditions. These variables combined make the chemical mitigation a challenging process, the target chemistry must be tested in well conditions and in representative samples to determine the optimum formulation and this process could take multiple iterations until it gets dial in. Furthermore, these dynamic conditions change over time making the optimization process a full-time effort.
The alternative of using fluid thermal treatments, using hot oil or water, are inefficient and normally used as a corrective action instead of a preventive measure. Obviously, the last option is mechanically removing the paraffin with scrapers or replace the elements showing issues. Both alternatives take time, resources, and loss of consequential production, and overall poor production performance of the well.
Normally the mitigation implemented at a field level has a combination of these techniques, always targeting the fluid, but not working at a tubular surface level.
This work describes the research, development and full implementation cases of a mature technology that uses surface thermal treatment of tubing to minimizes paraffin and asphaltene deposition within the tubing string. The technology first developed for heavy oil producers proved its wide application in paraffin with more than 1000 systems installed in South America. 
 

During the life of Yeso horizontal oil producers, well intervention and remediation is an essential step to ensure the maximum inflow volumes are being obtained and recovered volumes are matching the established production decline curves. Utilizing a Jet Junk Basket BHA with stick pipe has enabled Concho to successfully clean out a wellbore without the added cost of energized fluids and minimize the risk from getting stuck due to lost circulation. Frac sand that migrates into the wellbore during production and scale precipitation can hinder the well’s drawdown. One of the biggest challenges in being able to remove solids from the wellbore on the New Mexico Shelf is low bottom-hole reservoir pressure. Traditional cleanout methods that utilize reverse circulation and the assistance of energized fluids require higher bottom-hole reservoir pressures than that which is found on the New Mexico Shelf. The inability to maintain circulation during traditional cleanout operations has resulted in unsuccessful jobs and diminished economic efficiencies for projects in recent years prior to the application of the Venturi tool. This document describes case history and data complied over the workover results seen in 2015 and 2016. Overall, a total of 22 were successfully executed, providing an average of 35 barrels of oil per day.

Chlorine Dioxide (ClO2) has been used as a well damage removal and stimulation fluid since the late 1980’s. It was originally investigated as a means to remediate reservoirs of the permanently damaging effects of polymer, monomer, and polyacrylamide floods popular in the 1980’s across many conventional oilfields, including those in the Permian Basin of West Texas, U.S.A. Chlorine Dioxide is a strong oxidizer and highly effective biocide, very popular today for preparing frac waters and aiding in recycling produced waters, also to be used in fracturing.  Many petroleum engineers and oilfield production personnel are not aware of the chemistry, or services available to remove the damaging effects of polymers, polyacrylamide, frac gel, gel filter cake, biomass / biofilms, Hydrogen Sulfide (H2S), Iron Sulfide (FeS), Iron Oxide (Fe2O3), all species of bacteria including Sulfate Reducing Bacteria (SRB’s), and many other oxidizable particles that have plugged and otherwise damaged all types of wells.  Chlorine Dioxide has proven to be extremely effective in salt water disposal (SWD’s) and injection wells, but has also found an important role in vertical and horizontal producers having production challenges such as Iron Sulfide, due to the infiltration of SRB’s into the reservoir and the subsequent H2S, FeS, and H2S corrosion. This paper forms a summary of the ways Chlorine Dioxide, in conjunction with Hydrochloric acid (HCL), is used to remove wellbore damage, drastically reduce H2S levels, and overall, restore the well’s injectivity or productivity.  In addition, the paper outlines to the key aspects of treatment design to insure success while concentrating on practical field applications, as demonstrated in wells across the Permian Basin.