2021 Southwestern Petroleum Short Course Schedule

Thursday, August 26th

09:00AM - 09:50AM (Thursday)

Room 101
(05) Ball Lifting System for Deep Lift and Other Applications
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This paper discusses the principal of ball lifting systems (Lizard) for oil and gas wells and its possible applications. Typical applications are: 1. Acts as moving standing valve to minimize dry runs while reducing tubing wear. 2. Will continually operate in transition area; Lizard will move the to transition flow area to deliver ball to lifting sleeve, unloading wells and work itself to the bottom. 3. Increase lifting depth from 40 degrees to 75 degrees. 4. Stop yo-yo effect between two-piece plungers. A Lizard assembly for a plunger lift system is used to remove fluids and hydrocarbons from a subterranean wellbore includes a ball lifting sleeve meant to act as bumper spring or sit on bumper spring that engages (e.g., unites) and disengages with plunger assembly. The sleeve acts as an orifice to capture hydrocarbons from dead space around bumper spring and centrally force hydrocarbons to plunger assembly with maximum velocity. The ball lifting sleeve provides transfer of ball and liquid column to lifting plunger and assists in transitioning flow area. The sleeve provides softer fall rates reducing damage to lifting plunger and bumper spring. The Lizard assembly provides higher quality plunger operation further down curvature of deviated and horizontal wellbores providing deeper lifting capabilities. The sleeve provides standing valve principles to horizontal and vertical wellbores. The Lizard will unload high volume liquid loads by acting as a movable standing valve and gradually working its way to bumper spring. The Lizard can be utilized to replace bumper springs, reducing tubing restrictions downhole.

Presented by:

Sabrina Sullivan, Arthur Sullivan, and Ron Elkins 
Plungers and More

 

Artificial Lift
Room 102
(19) Coated Continuous Rod Optimizes Deviated and Corrosive Wells
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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.
 

Presented by:

Sara Million and Willians Padilla
Weatherford

 

Artificial Lift
Room 104
(36) Improving ESP Performance Combining Sand Control and Downhole Chemical Treatment: Case Studies in the Permian Basin
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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.
 

Presented by:

Ben Zapp, Lario Oil & Gas Co.
Shivani Vyas, Gustavo Gonzalez, L.A. Guanacas and Carlos Portilla, Odessa Separator, Inc.

 

Artificial Lift
Room 106
(21) Surface Diagnostics and Analysis in Optimization Technologies for Sucker Rod Pump Lifted Oil and Gas Wells
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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.

Presented by:

Ian Nickell, Champion X

 

Artificial Lift
Room 107
(06) Artificial Lift Selection for Horizontal Unconventional Wells
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Horizontal Unconventional declines have a rapidly declining hyperbolic decline section and a slower declining exponential decline section. Rapidly changing production volumes from the decline curve and more rapid changes from slugging gas as a result of undulations in the horizontal leg plus sand from massive frac jobs result in challenges in artificial lift selection. This paper will explore these challenges.

Presented by:

Jim Lea
Steve Gault

 

Artificial Lift
Room 108
(31) Enhancing Downhole Gas and Solids Separation and Lowering Operational Risk by Taking Advantage of Multiphase Flow Reversals
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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.
 

Presented by:

Scott Krell, Silver Energy Services
Anand Nagoo, Nagoo & Associates LLC
Jeff Saponja, Oilify

 

Artificial Lift
Room 110
(01) Field Performance Review Of High Strength Stainless Steel And Low Alloy Steel Sucker Rod In Harsh Environments
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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.

Presented by:

Rodrigo Barreto, Weatherford

 

Artificial Lift
Room 111
(18) Enhanced Optimization of Deviated Wells Utilizing Greenshot: A Permanent, Automated Fluid Level System
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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. 
 

Presented by:

Russell Messer and Victoria Pons
WellWorx Energy

 

Artificial Lift

10:00AM - 10:50AM (Thursday)

Room 101
(30) Optimizing Well Performance by Minimizing the Effects of Gas Slugs in Horizontal Wells: Surge Valve
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 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. 
 

Presented by:

Michael Conley, and Lee Weatherford Steward Energy
Donovan Sanchez and Luis Guanacas, Odessa Separator Inc.

 

Artificial Lift
Room 102
(40) Thermal Surface Treatment to Prevent Paraffin and Asphaltene Tubing Deposition
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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. 
 

Presented by:

Pablo Invierno, Global Technologies
Rodrigo Ruiz, Duxaoil Texas LLC

 

Prod. Handling
Room 104
(24) Measuring Wellbore Friction During Workover Operations
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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.
 

Presented by:

Walter Phillips, Wansco
Brandon Bridgman, Signal Hill Petroleum 

 

Artificial Lift
Room 106
(41) Protecting Flow Assurance and Maximizing Injectivity in the Midstream Water Space
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In the last 10-15 years, the US has seen a remarkable surge in the production of oil and natural gas as the industry learned how to properly complete and produce previously non-productive formations. With this increased hydrocarbon production, we have also seen an increase in the amount of water that is produced and must be managed. The large volumes of water that must be gathered, managed and eventually disposed, along with a growing trend for operators to prioritize their capital spend on drilling and completing revenue-producing wells, has created an opening for midstream water companies dedicated to produced water. While some of this produced water is treated to some degree and then used in ongoing completions to offset an equal volume of fresh water, the majority of it is destined for disposal via Class II UIC wells. Often this produce water has some degree of mineral scale over-saturation, or may be mixed with other waters that may or may not be compatible from a mineral standpoint. The water may contain various quantities of dispersed hydrocarbons, suspended organic material or inorganic solids such as iron sulfide or iron oxide - all of which can potentially impair the ability of the injection well to take water. Last, but not least, bacteria such as acid producing bacteria or sulfate reducing bacteria may be present in the produced water and may cause corrosion issues when allowed to contact bare steel and can generate biomass that again can impair injectivity. This paper will discuss the potential issues with the movement and injection of produced water outlined above. It will also outline and detail the best methods to monitor and analyze for these potential issues, the best approach to correcting or preventing of issues that may impair flow or injectivity and, finally, how to best monitor long-term to document success and properly optimize the preventative treatment program. 
 

Presented by:

Rick McCurdy, maxSWD

 

Prod. Handling
Room 107
(13) Early Application of Plungers in Gas Wells Producing Liquids
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It is recognized in the industry that it is wise to have AL in place before liquid loading is expected for a number of reasons.  These reasons include no production loss when the well drops below critical, convenience as the rig may/may not be available when the well drops below critical later, and in some cases some uplift is observed when installing plunger other AL before the rate drops below a calculated predicted critical. The discussion here concerns installing plunger lift in deviated wells in advance of predictions from well-known methods that say the well is not liquid loaded. However loading and significant uplifts in production are still observed with plunger contrary to what should be expected from commonly used industry indictors.  Some explanations are offered concerning the cases. The results should be of interest to operators that may experience the same situation/s.
 

Presented by:

Mark Gose Billy Hood, Elizabeth Clem and Andrew Borgan, BKV Artificial Lift
James F. Lea, PLTech, LLC

 

Artificial Lift
Room 108
(22) Downhole Gas and Sand Separation Solution for Dynamic Wells
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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.
 

Presented by:

Ken Nolen and Caitlin Shirey
WellWorx Energy

 

Artificial Lift
Room 110
(12) A Case Study: Optimized Valve Spacing in Gas Lift to Accommodate Maturing Reservoir Conditions in Permian Basin Wells
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In unconventional wells unstable dynamic behavior ensuing from an exchange of energy in the casing and tubing is the biggest challenge in gas lift design. As reservoir and tubing pressures decline from early conditions, wells show erratic behavior in decreasing fluid levels and hence unload and operate at variable depths. This case study presents the full workflow of creating an effective gas-lift design from concept initiation to execution and field installation. Successful spacing in gas lift valves for an available gas injection pressure, assures unloading from the deepest point of the tubing string (i.e., packer depth). The design should provide the number of valves for the available kickoff pressure and accommodate future reservoir decline. Two equations provide this flexibility, one for the first gas lift valve (from surface) and another for all deeper unloading valves. After performing a well delivery simulation with a nodal analysis program, a production rate versus injection gas curve is generated at each of the several potential depths of injection. Production rate and corresponding injection gas rate are selected at each depth. The rate from each depth is validated with measured data for outflow and reservoir inflow. Several designs are often needed so spacing criteria, and available kickoff pressure reach the desired injection depth and match the target production rate. This iterative methodology develops the gas lift spacing design allowing for a valve at a shallower depth to ensure unloading efficiency throughout the range of conditions and a valve just a joint above the packer to make production achievable at the lowest possible reservoir pressure. 
 

Presented by:

Haseeb Ahmed Janjua, ProLiftCo
John Martinez, Production Associates
Michael Swihart, ProLiftCo
 

Artificial Lift

11:00AM - 11:50AM (Thursday)

Room 101
(34) Digital Transformation for Sucker Rod Pump Operated Wells
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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. 
 

Presented by:

Mahmut Sengul, Noven Inc. 

 

Artificial Lift
Room 102
(28) 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
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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. 
 

Presented by:

Tracie Reed, Silverstream Energy Solutions, Inc.
Grant Shaffer, Flintec

 

Artificial Lift
Room 104
(07) Controlling Gas Slugs in ESP Using a New Downhole Gas Regulator: Case Studies
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Gas production is one of the main problems on ESP systems; causing premature failures and low efficiency, these are the reasons why many companies have developed a number of solutions to separate gas before reaches the pump. To solve this problem a New Downhole Gas Regulator has been developed in order to avoid large amounts of free gas flowing directly into the pump intake. This system regulates the amount of gas ingested by the pump so it will make easier for the pump stages to lift a fluid with a higher density (Less amount of gas in the multiphase flow). The system was designed to use the free gas flowing upward with the liquid to re solubilize the gas into the oil and produce the fluid with the lowest GOR and highest Rs possible. The ESP’s Downhole Regulator was designed based on each well conditions to maximize its efficiency.
 

Presented by:

Gustavo Gonzalez and Shivani Vyas, Odessa Separators Inc. 

 

Artificial Lift
Room 106
(03) Harmonic Mitigation Challenges in Unconventional ESP Applications
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Harmonic Mitigation Challenges in Unconventional ESP Applications 1. OBJECTIVES/SCOPE: Modern oil field producers face increasing pressure from utilities regarding harmonic compliance, and harmonic-related penalties can be severe. A more effective approach for mitigating VSD-induced power harmonics is presented, in which the unique electrical requirements of unconventional ESP applications are considered. The results of a field study demonstrate how a unique application of passive filter technology is far superior (both in technical performance and cost/benefit to the customer) when compared to outdated 12,18,24 pulse drive architectures and even AFE technology. 2. METHODS, PROCEDURES, PROCESS: Ensuring optimal harmonic reduction for VSD/ESP applications requires a more comprehensive approach, as well as a new application of established technology and new monitoring methods. Historical load analysis, field survey data (direct harmonic measurements), and consideration of future electrical loading changes must all be taken into account in a successful project. Moreover, verifying harmonic mitigation compliance in line with applicable standards requires new measurement methods, technologies, and planning. 3. RESULTS, OBSERVATIONS, CONCLUSIONS By focusing on field-scale harmonic reduction as opposed to performance at individual well sites, a better outcome for the customer and the supplying utility can be achieved. A field harmonics study encompassing 22 individual well sites is presented and harmonic current distortion reduction results out-perform utility requirements. Comparisons of various mitigation topologies are presented as they relate to the unique challenges of steep production decline applications, as well as challenging modern oilfield power quality environments. A new passive harmonic mitigation architecture is presented that adapts to changing electrical load, ensuring harmonic reduction is optimized as electrical loading declines. In addition, harmonic measurement methods and monitoring are discussed as they relate to recent changes in IEEE and IEC standard requirements and as an effective means of managing the routine maintenance requirements of passive harmonic filters. 4. NOVEL/ADDITIVE INFORMATION This paper will present realistic considerations and examples of real world results for the specifying engineer, when considering harmonic mitigation technology in unconventional VSD/ESP applications. In addition, new methods of employing remote power quality monitoring are presented which can prove invaluable to continued, reliable operation and compliance with applicable standards.

Presented by:

Ryan Dodson and  Davi Lacerda
Champion X
 

Artificial Lift
Room 107
(29) "Long and Slow" OR "Short and Fast" is NOT the Way to Go
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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.
 

Presented by:

Lynn Rowlan and Carrie-Anne Taylor, Echometer Company

 

Artificial Lift
Room 108
(16) Field Test Results from a Downhole Sucker Rod Sensor
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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! 
 

Presented by:

John MacKay
Well Innovation

 

Artificial Lift
Room 110
(11) High-Volume Rod Lift
More Information

Contemporary lift strategy for a newly completed well generally includes a period of unassisted flow followed by an Electrical Submersible Pump (ESP) system - up to half a dozen in certain situations. This is followed by one of a multitude of artificial lift options often culminating in a rod lift strategy for low-production to end of life. Ignoring entirely the financial component of these decisions, among the primary drivers of lift type selection is maximum uplift capability – an area in which rod lift has seen significant investment and improvement in recent years. Additional considerations include, but are not limited to, well-bore characteristics, equipment capability, and reliability.

This paper will seek to submit for consideration an alternative strategy for high-volume artificial lift made possible by recent improvements to what has historically been a popular, albeit marginal, lift type: reciprocating rod lift.
 

Presented by:

Erik Jacson and Chris Lauden
Weatherford

 

Artificial Lift
Room 111
(25) Continuous Rod: Improving Run Times in Unconventional Wells
More Information

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.
 

Presented by:

Victoria Pons, Pons Energy Analytics 
Anne Marie Weaver, Lightning Production Services
L.J. Guillotte, Lightning Production Services
Andrew Wlazlo, Triple Crown Resources

Artificial Lift

01:00PM - 01:50PM (Thursday)

Room 101
(43) Multiphase Flow Performance in Piping Systems
More Information

Multiphase flow is found in various places both in nature and in practice, however, multiphase flow is prevalent in the petroleum production industry. This phenomenon brings about a major problem of pressure loss in piping systems and results in a loss in production. Multiphase flow has been studied for years however, with the increase in unconventional engineering methods, there is now a greater need for the study of multiphase flow. This study investigates various phenomena created by multiphase flow such as flow patterns known as flow regimes and pressure loss created by friction and different fluid phase properties. An experimental system was designed to represent situations in the oil and gas industry. The system included pipe orientations of horizontal, inclined and vertical sections as experienced during petroleum migration from the reservoir to the surface. To represent multiphase flow in the experimental system, water was used to represent the oil and compressed air to represent gas in the wellbore. The pressure difference throughout the system was the system was calculated using the Beggs and Brill Correlation and the Lockhart Martinelli Parameter. Experimental pressure differences were measured for different parts of the system while observing the flow regimes created by multiphase fluid interaction. Through the research methods, it was found that the majority of the pressure losses occurred in the elbows and most frictional pressure loss occurred in the vertical 3ft pipe while the 45° & 90° downhill pipes had an increase in pressure. 
 

Presented by:

Mahmoud Elsharafi,  Christopher Alexis, and  Trevon Antoine
Midwestern State University

 

Reservoir Operation
Room 102
(02) ESP Trend Analytics: Merging Data Science with Application Engineering Knowledge To Improve Operational State Identification
More Information

A process for modeling multivariate Electric Submersible Pump data in a central host system is proposed in to support managing fields by exception by using artificial intelligence models to identify failure modes and operating conditions. The AI model enables operators to immediately identify failure modes and operational conditions, as it is continuously analyzing, facilitating quicker decision making. It also increases the number of wells an operator can effectively manage, and can be used as an educational tool, empowering users to interpret complex ESP trends. Methods, Procedures, Process: The approach to Electric Submersible Pump trend analytics is based on field data observed from over 1400 wells across the United States. Standard trend data for ESPs such as Motor Frequency, Surface Motor Current, Downhole Motor Temperature, and Pump Intake Pressure are considered in the model. A process is described for cleaning and standardizing raw sensor data, detecting anomalous operating conditions, and classifying the anomalies using multivariate statistical analysis. The model recommended is extensible to consider arbitrarily many sensor signals in classifying the anomalies. Results, Observations, Conclusions: Upon sequential iterations the accuracy of operational conditions classifications improved to about 80%, and eventually achieved 90% accuracy after multiple validation cycles on the 130 test ESP wells. We determined the algorithms we are using to classify operating conditions limits the accuracy but increases the meaning to the end user by the way it is presented. There are more advanced algorithms available with the potential of achieving higher accuracy but at a cost of understanding and explaining the results to the user. The broken shaft and gas slugging cases studies presented in this paper showcase the value driven by the model’s ability to identify failures and operational conditions that allow expedited planning of resolution procedures. Thereby reducing the downtime of high production ESP wells and the impact of lost production. The model presented in this paper will continue to expand into more classifications over time. Further work is required to build out recommendations for ‘next-steps’ based on the classifications presented. This will enhance the understanding of why the anomaly is occurring and the steps to take to resolve the problem. Continuing on this path will inevitably lead us to the beginning stages of autonomous control. Novel/Additive Information: The ESP community is adapting to new ways of analyzing trends over time. Circular ammeter charts were the only piece of downhole information available for many years. As downhole sensors became standard in the industry, new variables became available but that also meant the learning curve became exponentially steep overnight. This method for analyzing Electric Submersible Pump trend data is novel in the diversity of its data sources (over 1400 wells representing diverse reservoir conditions and well designs) and in its ability to generalize wells with diverse sensor configurations and levels of data quality/availability.

Presented by:

Dylan Bucanek

ChampionX

 

Artificial Lift
Room 104
(08) Sand Control Management in ESP Case Studies Delaware Basin
More Information

This paper proposes an analytical methodology that consists of an evaluation of the particle size distribution, viability for the use of sand screens and centrifugal separation systems for sand control management in wells with high sand and fluid production producing through an ESP. All the technical considerations are explained focusing on the information required and the parameters analyzed to recommend the most accurate design for sand control; selected approaches and models that have been developed to improve the runtime due to sand issues. The methodology for the evaluation and selection of sand control systems was proven in a field with historical low run time due to sand problems in the ESPs. The methodology is explained with the theoretical concepts and through several case studies in the Permian Basin.
 

Presented by:

Gustavo Gonzalez, Luis Guanacas, Scott Vestal, Odessa Separators Inc.

 

Artificial Lift
Room 106
(09) Carbon Fiber Sucker Rods Increase Production, Reduce Wear
More Information

Carbon fiber sucker rods were first installed in wells in 2015, and significant material and design improvements have been made since. Originally developed to rod pump the deepest wells with small-diameter tubing, high-strength, light-weight carbon fiber rods are optimal for rod pumping through the build section in pad-drilled wells. This paper will show how carbon fiber rods reduce friction and side-wall loads through wellbore deviations, and enable higher ESP-like rates of production when operated with long stroke beam pumping units.
 

Presented by:

Michell Hale, Megalex Rods

 

Artificial Lift
Room 107
(14) Visualizing Electrical Submersible Pump (ESP) and Sucker Rod Pump (SRP) Gas Separation
More Information

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. 
 

Presented by:

James F. Lea, PL Tech
David Divine, Valiant Artificial Lift Solutions
Lynn Rowlan, Echometer Company

 

Artificial Lift
Room 108
(26) Vertical vs. Deviated Wells: Balance of Forces & Equations
More Information

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. 
 

Presented by:

Victoria Pons, Pons Energy Analytics

 

Artificial Lift
Room 110
(10) Lessons Learned with Jet Pumps in a Low Pressure, Gassy and Sandy Reservoir with High Deviation
More Information

Lessons Learned with Jet Pumps in a Low Pressure Gassy and Sandy Reservoir with High Deviation The jet pump is said to be a flexible tool adaptable to produce where other artificial lift methods have shortcomings: however, it too requires special considerations in search of economics and life cycle optimization. This report reviews design and equipment upgrades to the jet pump system with solutions and continued shortcomings after one year of operation. The mature low pressure gassy and sandy reservoir located in a remote jungle has been using jet pumps since it was first developed in the 70’s because the field lacks the infrastructure to make rig workovers feasible. The feature of the jet pump most valued in this field is its ability of downhole pump recovery by reverse circulation. Jet pumps were first introduced after development of the full hydraulic piston pump product line and many jet pumps were adapted to equipment designed for positive displacement downhole pumps. Manufacturing and engineered solutions were affected by the late 80’s oil glut, almost wiping out hydraulic lift and completely eliminated the hydraulic piston pump. Fields that need features of the jet pump persist in finding solutions to shortcomings in the same way that solutions are found for other lift methods. The major advantages of the jet pump include its reverse circulation retrieval, tolerance to sand and gas as well adaptability to existing completion for well testing or flexibility in lift capacity. Two other advantages important to the field referenced in this report is the range of deviation that a jet pump can accept and the economics in multiple well pads. Limitations have been attributed to a lack of understanding of the efficiency in energy transfer in low pressure and gassy mediums. Lessons learned in this case history can prove useful in other fields with similar characteristics. 
 

Presented by:

Jesse Hernandez, Global Petroleum Technologies
Smarten Ryk Maneking, Pertamina

 

Artificial Lift
Room 111
(17) Minimizing Failure Frequencies in the Midcon Area by Root Cause Failure Analysis (RCFA) Methods And Design Optimizations
More Information

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.   
 

Presented by:

Oscar E. Martinez, Weatherford

 

Artificial Lift

02:00PM - 02:50PM (Thursday)

Room 102
(23) Production of Mature Unconventional Wells Using Jet Pumps, Recommendations for Producing Wells with Low Producing Bottomhole Pressures
More Information

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. 
 

Presented by:

Osman Nunez-Pino, Liberty Lift Solutions, LLC

 

Artificial Lift
Room 104
(42) Chemical Management Program from the Point of View of the Operator and the Chemical Vendor
More Information

A Chemical Management Program is an integral part of an overall effort to reduce downhole and surface failures.  The success of a Chemical Management Program depends upon the Operator and the Chemical vendor understanding the expectations and responsibilities assigned to each party.  This paper identifies the critical tasks associated with a successful program to aid in clarification as to which party is responsible for each.  The terms of the business contract would then be defined around these tasks. 
 

Presented by:

Dylan Bucanek and Chase Schippers, Champion X
Rob Vincent, PLTech, LLC

Prod. Handling
Room 107
(37) Viscoelastic Representation of Sucker Rod Pump Systems
More Information

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. 
 

Presented by:

Sheldon Wang, Abbey Henderson, Sean T. Aleman and Trent Creacy,  Midwestern State University
Lynn Rowlan and Carrie-Anne Taylor,  Echometer Company

 

Artificial Lift
Room 108
(32) Gas Issues with Downhole Sucker Rod Pump Operations
More Information

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.  

Presented by:

Benny J. Williams

Q2 Artificial Lift Services

 

Artificial Lift
Room 110
(33) New Gas Bypass System for Unconventional Wells on ESP
More Information

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.  
 

Presented by:

Kimberly Selman and Matt Raglin
WellWorx Energy

 

Artificial Lift
Room 111
(38) Increase MTBF by Pumping The Curve With Thermoplastic Liners
More Information

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.
 

Presented by:

Victoria Pons, Ph. D., Pons Energy Analytics
Anne Marie Weaver and L.J. Guillotte, Lightning Production Services
Justin Lundquist, P.E., Revolution Resources
 

Drilling Operations

03:30PM - 04:20PM (Thursday)

Room 104
(44) A Simple, Cost Effective Alternative to Crosslinked Guar Systems that Allows for the Use of Produced Water
More Information

Environmental concerns and increasing costs are creating a need for a polymer that will allow the use of a high salt, high hardness water in the making of a viscosified frac fluid. Any new polymer would also need to tick the boxes for cost, rheology, HS&E characteristics as well as breaking in the reservoir. Past development efforts have focused on improving organic-based polymers. A new approach was taken and a shift was made to the use of silica-based polymer. This paper will review silica chemistry but the focus will be on West Texas field trials where the silica gel was used as an alternative to 20 lb/Mgal crosslinked-guar. Covered topics will include; chemistry of produced water, making the silica gel on-location, pumping characteristics, cost and impact on production.
 

Presented by:

Carl Harman, Satanta Oil
Mike McDonald, PQ Corporation

 

Reservoir Operation
Room 107
(15) Tubing Flow Model for Predicting Bottom Hole Pressure During CO2 Injection: Correlation of Pressure Data From Large-Scale Storage Projects
More Information

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). 

Presented by:

R.T. Okwen, Illinois State Geological Survey
J. F. Lea, Production & Lift Technology

 

Artificial Lift
Room 110
(27) Optimum Shot Peen Process On The Sucker Rod Fatigue Life
More Information

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.
 

Presented by:

Santhosh Ramaswamy and Oscar E . Martinez, Weatherford

 

Artificial Lift
Room 111
(45) MSLE Gas Separator - Multi-Stage Limited-Entry Explained and Test Results
More Information

A new gas separation technology was released last year with the goal of creating a substantially increased volume capacity and therefore significantly improved separation quality through application of a process known as limited-entry. This process is more commonly applied to well fracturing and other stimulation procedures wherein the principle is applied to create an equal distribution of fluids to be pumped into an expansive length of producing formation or a variety of formation qualities at once. In the Multi-Stage Limited-Entry (MSLE) separator’s design that same principle is utilized, but in a reversed method such that the fluids being ingested into the gas separator are purposefully restricted through the uppermost chamber and thus the remaining volume must then be handled by the next chamber stacked below. This process continues until the entire volume of fluids designed to be pumped from the well are ingested by the separator stack, at the designed slow pace, and pumped through the rod pump BHA then to surface. The most notable benefit of applying this process to gas separation is that it becomes feasible to slow the intake of the gas-laden fluids by an extreme amount; far more than is possible by simply running a much larger OD poor-boy style separator or a much smaller OD packer-style separator. Slowing down the intake of fluids by dividing the work equally into a stacked set of separation chambers allow for a minimum target of 1.0”/second or less fluid drawdown velocity to become possible which is 6 times slower than other separators are designed for and what their claimed capacities are derived from, yet is what will directly drive far greater ability to reach exceptional levels of gas separation quality and, ultimately, far superior rod pumping production and overall operational success. The MSLE separator manipulates the wellbore and fluid intake path such that the historic and only method of increasing separation capacity, adding more dead-space cross-sectional area, is no longer the primary and also limiting means of improving separation performance. There is only a limited amount of room to work with in historic separation options in the typically applied casing sizes of 7” and, more commonly for the Permian Basin, 5.5”. Getting too aggressive with design applications in effort to add dead-space ultimately leads to either extreme annular superficial gas velocity (resulting in fluid blow-by) when applying a large OD poor-boor style separator with tight tolerance to the casing ID or going the other direction, pressure drop inside the flow-through tube (resulting in potential depositions/plugging) when applying a small OD packer-style separator. This paper will explain the process of limited-entry as it applies to gas separation design and how the resultant MSLE separator functions differ in regards to other commonly applied separators. Further, a notable series of MSLE separator tests will be reviewed to illustrate lessons learned, design improvements implemented, and overall performance achieved in a variety of well conditions. 
 

Presented by:

Brian Ellithorp, BlackJack Production Tools

 

Well Completion and Simulation

Friday, August 27th

08:00AM - 08:50AM (Friday)

Room 101
(17) Minimizing Failure Frequencies in the Midcon Area by Root Cause Failure Analysis (RCFA) Methods And Design Optimizations
More Information

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.   
 

Presented by:

Oscar E. Martinez, Weatherford

 

Artificial Lift
Room 102
(23) Production of Mature Unconventional Wells Using Jet Pumps, Recommendations for Producing Wells with Low Producing Bottomhole Pressures
More Information

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. 
 

Presented by:

Osman Nunez-Pino, Liberty Lift Solutions, LLC

 

Artificial Lift
Room 103
(36) Improving ESP Performance Combining Sand Control and Downhole Chemical Treatment: Case Studies in the Permian Basin
More Information

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.
 

Presented by:

Ben Zapp, Lario Oil & Gas Co.
Shivani Vyas, Gustavo Gonzalez, L.A. Guanacas and Carlos Portilla, Odessa Separator, Inc.

 

Artificial Lift
Room 104
(42) Chemical Management Program from the Point of View of the Operator and the Chemical Vendor
More Information

A Chemical Management Program is an integral part of an overall effort to reduce downhole and surface failures.  The success of a Chemical Management Program depends upon the Operator and the Chemical vendor understanding the expectations and responsibilities assigned to each party.  This paper identifies the critical tasks associated with a successful program to aid in clarification as to which party is responsible for each.  The terms of the business contract would then be defined around these tasks. 
 

Presented by:

Dylan Bucanek and Chase Schippers, Champion X
Rob Vincent, PLTech, LLC

Prod. Handling
Room 106
(09) Carbon Fiber Sucker Rods Increase Production, Reduce Wear
More Information

Carbon fiber sucker rods were first installed in wells in 2015, and significant material and design improvements have been made since. Originally developed to rod pump the deepest wells with small-diameter tubing, high-strength, light-weight carbon fiber rods are optimal for rod pumping through the build section in pad-drilled wells. This paper will show how carbon fiber rods reduce friction and side-wall loads through wellbore deviations, and enable higher ESP-like rates of production when operated with long stroke beam pumping units.
 

Presented by:

Michell Hale, Megalex Rods

 

Artificial Lift
Room 107
(14) Visualizing Electrical Submersible Pump (ESP) and Sucker Rod Pump (SRP) Gas Separation
More Information

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. 
 

Presented by:

James F. Lea, PL Tech
David Divine, Valiant Artificial Lift Solutions
Lynn Rowlan, Echometer Company

 

Artificial Lift
Room 108
(32) Gas Issues with Downhole Sucker Rod Pump Operations
More Information

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.  

Presented by:

Benny J. Williams

Q2 Artificial Lift Services

 

Artificial Lift
Room 110
(12) A Case Study: Optimized Valve Spacing in Gas Lift to Accommodate Maturing Reservoir Conditions in Permian Basin Wells
More Information

In unconventional wells unstable dynamic behavior ensuing from an exchange of energy in the casing and tubing is the biggest challenge in gas lift design. As reservoir and tubing pressures decline from early conditions, wells show erratic behavior in decreasing fluid levels and hence unload and operate at variable depths. This case study presents the full workflow of creating an effective gas-lift design from concept initiation to execution and field installation. Successful spacing in gas lift valves for an available gas injection pressure, assures unloading from the deepest point of the tubing string (i.e., packer depth). The design should provide the number of valves for the available kickoff pressure and accommodate future reservoir decline. Two equations provide this flexibility, one for the first gas lift valve (from surface) and another for all deeper unloading valves. After performing a well delivery simulation with a nodal analysis program, a production rate versus injection gas curve is generated at each of the several potential depths of injection. Production rate and corresponding injection gas rate are selected at each depth. The rate from each depth is validated with measured data for outflow and reservoir inflow. Several designs are often needed so spacing criteria, and available kickoff pressure reach the desired injection depth and match the target production rate. This iterative methodology develops the gas lift spacing design allowing for a valve at a shallower depth to ensure unloading efficiency throughout the range of conditions and a valve just a joint above the packer to make production achievable at the lowest possible reservoir pressure. 
 

Presented by:

Haseeb Ahmed Janjua, ProLiftCo
John Martinez, Production Associates
Michael Swihart, ProLiftCo
 

Artificial Lift
Room 111
(25) Continuous Rod: Improving Run Times in Unconventional Wells
More Information

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.
 

Presented by:

Victoria Pons, Pons Energy Analytics 
Anne Marie Weaver, Lightning Production Services
L.J. Guillotte, Lightning Production Services
Andrew Wlazlo, Triple Crown Resources

Artificial Lift

09:00AM - 09:50AM (Friday)

Room 101
(31) Enhancing Downhole Gas and Solids Separation and Lowering Operational Risk by Taking Advantage of Multiphase Flow Reversals
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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.
 

Presented by:

Scott Krell, Silver Energy Services
Anand Nagoo, Nagoo & Associates LLC
Jeff Saponja, Oilify

 

Artificial Lift
Room 103
(30) Optimizing Well Performance by Minimizing the Effects of Gas Slugs in Horizontal Wells: Surge Valve
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 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. 
 

Presented by:

Michael Conley, and Lee Weatherford Steward Energy
Donovan Sanchez and Luis Guanacas, Odessa Separator Inc.

 

Artificial Lift
Room 104
(37) Viscoelastic Representation of Sucker Rod Pump Systems
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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. 
 

Presented by:

Sheldon Wang, Abbey Henderson, Sean T. Aleman and Trent Creacy,  Midwestern State University
Lynn Rowlan and Carrie-Anne Taylor,  Echometer Company

 

Artificial Lift
Room 106
(26) Vertical vs. Deviated Wells: Balance of Forces & Equations
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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. 
 

Presented by:

Victoria Pons, Pons Energy Analytics

 

Artificial Lift
Room 107
(15) Tubing Flow Model for Predicting Bottom Hole Pressure During CO2 Injection: Correlation of Pressure Data From Large-Scale Storage Projects
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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). 

Presented by:

R.T. Okwen, Illinois State Geological Survey
J. F. Lea, Production & Lift Technology

 

Artificial Lift
Room 110
(10) Lessons Learned with Jet Pumps in a Low Pressure, Gassy and Sandy Reservoir with High Deviation
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Lessons Learned with Jet Pumps in a Low Pressure Gassy and Sandy Reservoir with High Deviation The jet pump is said to be a flexible tool adaptable to produce where other artificial lift methods have shortcomings: however, it too requires special considerations in search of economics and life cycle optimization. This report reviews design and equipment upgrades to the jet pump system with solutions and continued shortcomings after one year of operation. The mature low pressure gassy and sandy reservoir located in a remote jungle has been using jet pumps since it was first developed in the 70’s because the field lacks the infrastructure to make rig workovers feasible. The feature of the jet pump most valued in this field is its ability of downhole pump recovery by reverse circulation. Jet pumps were first introduced after development of the full hydraulic piston pump product line and many jet pumps were adapted to equipment designed for positive displacement downhole pumps. Manufacturing and engineered solutions were affected by the late 80’s oil glut, almost wiping out hydraulic lift and completely eliminated the hydraulic piston pump. Fields that need features of the jet pump persist in finding solutions to shortcomings in the same way that solutions are found for other lift methods. The major advantages of the jet pump include its reverse circulation retrieval, tolerance to sand and gas as well adaptability to existing completion for well testing or flexibility in lift capacity. Two other advantages important to the field referenced in this report is the range of deviation that a jet pump can accept and the economics in multiple well pads. Limitations have been attributed to a lack of understanding of the efficiency in energy transfer in low pressure and gassy mediums. Lessons learned in this case history can prove useful in other fields with similar characteristics. 
 

Presented by:

Jesse Hernandez, Global Petroleum Technologies
Smarten Ryk Maneking, Pertamina

 

Artificial Lift
Room 111
(45) MSLE Gas Separator - Multi-Stage Limited-Entry Explained and Test Results
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A new gas separation technology was released last year with the goal of creating a substantially increased volume capacity and therefore significantly improved separation quality through application of a process known as limited-entry. This process is more commonly applied to well fracturing and other stimulation procedures wherein the principle is applied to create an equal distribution of fluids to be pumped into an expansive length of producing formation or a variety of formation qualities at once. In the Multi-Stage Limited-Entry (MSLE) separator’s design that same principle is utilized, but in a reversed method such that the fluids being ingested into the gas separator are purposefully restricted through the uppermost chamber and thus the remaining volume must then be handled by the next chamber stacked below. This process continues until the entire volume of fluids designed to be pumped from the well are ingested by the separator stack, at the designed slow pace, and pumped through the rod pump BHA then to surface. The most notable benefit of applying this process to gas separation is that it becomes feasible to slow the intake of the gas-laden fluids by an extreme amount; far more than is possible by simply running a much larger OD poor-boy style separator or a much smaller OD packer-style separator. Slowing down the intake of fluids by dividing the work equally into a stacked set of separation chambers allow for a minimum target of 1.0”/second or less fluid drawdown velocity to become possible which is 6 times slower than other separators are designed for and what their claimed capacities are derived from, yet is what will directly drive far greater ability to reach exceptional levels of gas separation quality and, ultimately, far superior rod pumping production and overall operational success. The MSLE separator manipulates the wellbore and fluid intake path such that the historic and only method of increasing separation capacity, adding more dead-space cross-sectional area, is no longer the primary and also limiting means of improving separation performance. There is only a limited amount of room to work with in historic separation options in the typically applied casing sizes of 7” and, more commonly for the Permian Basin, 5.5”. Getting too aggressive with design applications in effort to add dead-space ultimately leads to either extreme annular superficial gas velocity (resulting in fluid blow-by) when applying a large OD poor-boor style separator with tight tolerance to the casing ID or going the other direction, pressure drop inside the flow-through tube (resulting in potential depositions/plugging) when applying a small OD packer-style separator. This paper will explain the process of limited-entry as it applies to gas separation design and how the resultant MSLE separator functions differ in regards to other commonly applied separators. Further, a notable series of MSLE separator tests will be reviewed to illustrate lessons learned, design improvements implemented, and overall performance achieved in a variety of well conditions. 
 

Presented by:

Brian Ellithorp, BlackJack Production Tools

 

Well Completion and Simulation

10:00AM - 10:50AM (Friday)

Room 101
(44) A Simple, Cost Effective Alternative to Crosslinked Guar Systems that Allows for the Use of Produced Water
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Environmental concerns and increasing costs are creating a need for a polymer that will allow the use of a high salt, high hardness water in the making of a viscosified frac fluid. Any new polymer would also need to tick the boxes for cost, rheology, HS&E characteristics as well as breaking in the reservoir. Past development efforts have focused on improving organic-based polymers. A new approach was taken and a shift was made to the use of silica-based polymer. This paper will review silica chemistry but the focus will be on West Texas field trials where the silica gel was used as an alternative to 20 lb/Mgal crosslinked-guar. Covered topics will include; chemistry of produced water, making the silica gel on-location, pumping characteristics, cost and impact on production.
 

Presented by:

Carl Harman, Satanta Oil
Mike McDonald, PQ Corporation

 

Reservoir Operation
Room 102
(02) ESP Trend Analytics: Merging Data Science with Application Engineering Knowledge To Improve Operational State Identification
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A process for modeling multivariate Electric Submersible Pump data in a central host system is proposed in to support managing fields by exception by using artificial intelligence models to identify failure modes and operating conditions. The AI model enables operators to immediately identify failure modes and operational conditions, as it is continuously analyzing, facilitating quicker decision making. It also increases the number of wells an operator can effectively manage, and can be used as an educational tool, empowering users to interpret complex ESP trends. Methods, Procedures, Process: The approach to Electric Submersible Pump trend analytics is based on field data observed from over 1400 wells across the United States. Standard trend data for ESPs such as Motor Frequency, Surface Motor Current, Downhole Motor Temperature, and Pump Intake Pressure are considered in the model. A process is described for cleaning and standardizing raw sensor data, detecting anomalous operating conditions, and classifying the anomalies using multivariate statistical analysis. The model recommended is extensible to consider arbitrarily many sensor signals in classifying the anomalies. Results, Observations, Conclusions: Upon sequential iterations the accuracy of operational conditions classifications improved to about 80%, and eventually achieved 90% accuracy after multiple validation cycles on the 130 test ESP wells. We determined the algorithms we are using to classify operating conditions limits the accuracy but increases the meaning to the end user by the way it is presented. There are more advanced algorithms available with the potential of achieving higher accuracy but at a cost of understanding and explaining the results to the user. The broken shaft and gas slugging cases studies presented in this paper showcase the value driven by the model’s ability to identify failures and operational conditions that allow expedited planning of resolution procedures. Thereby reducing the downtime of high production ESP wells and the impact of lost production. The model presented in this paper will continue to expand into more classifications over time. Further work is required to build out recommendations for ‘next-steps’ based on the classifications presented. This will enhance the understanding of why the anomaly is occurring and the steps to take to resolve the problem. Continuing on this path will inevitably lead us to the beginning stages of autonomous control. Novel/Additive Information: The ESP community is adapting to new ways of analyzing trends over time. Circular ammeter charts were the only piece of downhole information available for many years. As downhole sensors became standard in the industry, new variables became available but that also meant the learning curve became exponentially steep overnight. This method for analyzing Electric Submersible Pump trend data is novel in the diversity of its data sources (over 1400 wells representing diverse reservoir conditions and well designs) and in its ability to generalize wells with diverse sensor configurations and levels of data quality/availability.

Presented by:

Dylan Bucanek

ChampionX

 

Artificial Lift
Room 103
(34) Digital Transformation for Sucker Rod Pump Operated Wells
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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. 
 

Presented by:

Mahmut Sengul, Noven Inc. 

 

Artificial Lift
Room 104
(07) Controlling Gas Slugs in ESP Using a New Downhole Gas Regulator: Case Studies
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Gas production is one of the main problems on ESP systems; causing premature failures and low efficiency, these are the reasons why many companies have developed a number of solutions to separate gas before reaches the pump. To solve this problem a New Downhole Gas Regulator has been developed in order to avoid large amounts of free gas flowing directly into the pump intake. This system regulates the amount of gas ingested by the pump so it will make easier for the pump stages to lift a fluid with a higher density (Less amount of gas in the multiphase flow). The system was designed to use the free gas flowing upward with the liquid to re solubilize the gas into the oil and produce the fluid with the lowest GOR and highest Rs possible. The ESP’s Downhole Regulator was designed based on each well conditions to maximize its efficiency.
 

Presented by:

Gustavo Gonzalez and Shivani Vyas, Odessa Separators Inc. 

 

Artificial Lift
Room 106
(41) Protecting Flow Assurance and Maximizing Injectivity in the Midstream Water Space
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In the last 10-15 years, the US has seen a remarkable surge in the production of oil and natural gas as the industry learned how to properly complete and produce previously non-productive formations. With this increased hydrocarbon production, we have also seen an increase in the amount of water that is produced and must be managed. The large volumes of water that must be gathered, managed and eventually disposed, along with a growing trend for operators to prioritize their capital spend on drilling and completing revenue-producing wells, has created an opening for midstream water companies dedicated to produced water. While some of this produced water is treated to some degree and then used in ongoing completions to offset an equal volume of fresh water, the majority of it is destined for disposal via Class II UIC wells. Often this produce water has some degree of mineral scale over-saturation, or may be mixed with other waters that may or may not be compatible from a mineral standpoint. The water may contain various quantities of dispersed hydrocarbons, suspended organic material or inorganic solids such as iron sulfide or iron oxide - all of which can potentially impair the ability of the injection well to take water. Last, but not least, bacteria such as acid producing bacteria or sulfate reducing bacteria may be present in the produced water and may cause corrosion issues when allowed to contact bare steel and can generate biomass that again can impair injectivity. This paper will discuss the potential issues with the movement and injection of produced water outlined above. It will also outline and detail the best methods to monitor and analyze for these potential issues, the best approach to correcting or preventing of issues that may impair flow or injectivity and, finally, how to best monitor long-term to document success and properly optimize the preventative treatment program. 
 

Presented by:

Rick McCurdy, maxSWD

 

Prod. Handling
Room 107
(29) "Long and Slow" OR "Short and Fast" is NOT the Way to Go
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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.
 

Presented by:

Lynn Rowlan and Carrie-Anne Taylor, Echometer Company

 

Artificial Lift
Room 108
(22) Downhole Gas and Sand Separation Solution for Dynamic Wells
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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.
 

Presented by:

Ken Nolen and Caitlin Shirey
WellWorx Energy

 

Artificial Lift
Room 110
(27) Optimum Shot Peen Process On The Sucker Rod Fatigue Life
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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.
 

Presented by:

Santhosh Ramaswamy and Oscar E . Martinez, Weatherford

 

Artificial Lift
Room 111
(18) Enhanced Optimization of Deviated Wells Utilizing Greenshot: A Permanent, Automated Fluid Level System
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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. 
 

Presented by:

Russell Messer and Victoria Pons
WellWorx Energy

 

Artificial Lift

11:00AM - 11:50AM (Friday)

Room 101
(01) Field Performance Review Of High Strength Stainless Steel And Low Alloy Steel Sucker Rod In Harsh Environments
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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.

Presented by:

Rodrigo Barreto, Weatherford

 

Artificial Lift
Room 102
(28) 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
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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. 
 

Presented by:

Tracie Reed, Silverstream Energy Solutions, Inc.
Grant Shaffer, Flintec

 

Artificial Lift
Room 103
(43) Multiphase Flow Performance in Piping Systems
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Multiphase flow is found in various places both in nature and in practice, however, multiphase flow is prevalent in the petroleum production industry. This phenomenon brings about a major problem of pressure loss in piping systems and results in a loss in production. Multiphase flow has been studied for years however, with the increase in unconventional engineering methods, there is now a greater need for the study of multiphase flow. This study investigates various phenomena created by multiphase flow such as flow patterns known as flow regimes and pressure loss created by friction and different fluid phase properties. An experimental system was designed to represent situations in the oil and gas industry. The system included pipe orientations of horizontal, inclined and vertical sections as experienced during petroleum migration from the reservoir to the surface. To represent multiphase flow in the experimental system, water was used to represent the oil and compressed air to represent gas in the wellbore. The pressure difference throughout the system was the system was calculated using the Beggs and Brill Correlation and the Lockhart Martinelli Parameter. Experimental pressure differences were measured for different parts of the system while observing the flow regimes created by multiphase fluid interaction. Through the research methods, it was found that the majority of the pressure losses occurred in the elbows and most frictional pressure loss occurred in the vertical 3ft pipe while the 45° & 90° downhill pipes had an increase in pressure. 
 

Presented by:

Mahmoud Elsharafi,  Christopher Alexis, and  Trevon Antoine
Midwestern State University

 

Reservoir Operation
Room 104
(24) Measuring Wellbore Friction During Workover Operations
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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.
 

Presented by:

Walter Phillips, Wansco
Brandon Bridgman, Signal Hill Petroleum 

 

Artificial Lift
Room 106
(21) Surface Diagnostics and Analysis in Optimization Technologies for Sucker Rod Pump Lifted Oil and Gas Wells
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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.

Presented by:

Ian Nickell, Champion X

 

Artificial Lift
Room 107
(06) Artificial Lift Selection for Horizontal Unconventional Wells
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Horizontal Unconventional declines have a rapidly declining hyperbolic decline section and a slower declining exponential decline section. Rapidly changing production volumes from the decline curve and more rapid changes from slugging gas as a result of undulations in the horizontal leg plus sand from massive frac jobs result in challenges in artificial lift selection. This paper will explore these challenges.

Presented by:

Jim Lea
Steve Gault

 

Artificial Lift
Room 108
(16) Field Test Results from a Downhole Sucker Rod Sensor
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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! 
 

Presented by:

John MacKay
Well Innovation

 

Artificial Lift
Room 110
(11) High-Volume Rod Lift
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Contemporary lift strategy for a newly completed well generally includes a period of unassisted flow followed by an Electrical Submersible Pump (ESP) system - up to half a dozen in certain situations. This is followed by one of a multitude of artificial lift options often culminating in a rod lift strategy for low-production to end of life. Ignoring entirely the financial component of these decisions, among the primary drivers of lift type selection is maximum uplift capability – an area in which rod lift has seen significant investment and improvement in recent years. Additional considerations include, but are not limited to, well-bore characteristics, equipment capability, and reliability.

This paper will seek to submit for consideration an alternative strategy for high-volume artificial lift made possible by recent improvements to what has historically been a popular, albeit marginal, lift type: reciprocating rod lift.
 

Presented by:

Erik Jacson and Chris Lauden
Weatherford

 

Artificial Lift
Room 111
(38) Increase MTBF by Pumping The Curve With Thermoplastic Liners
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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.
 

Presented by:

Victoria Pons, Ph. D., Pons Energy Analytics
Anne Marie Weaver and L.J. Guillotte, Lightning Production Services
Justin Lundquist, P.E., Revolution Resources
 

Drilling Operations

12:00PM - 12:50PM (Friday)

Room 101
(40) Thermal Surface Treatment to Prevent Paraffin and Asphaltene Tubing Deposition
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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. 
 

Presented by:

Pablo Invierno, Global Technologies
Rodrigo Ruiz, Duxaoil Texas LLC

 

Prod. Handling
Room 102
(19) Coated Continuous Rod Optimizes Deviated and Corrosive Wells
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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.
 

Presented by:

Sara Million and Willians Padilla
Weatherford

 

Artificial Lift
Room 103
(05) Ball Lifting System for Deep Lift and Other Applications
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This paper discusses the principal of ball lifting systems (Lizard) for oil and gas wells and its possible applications. Typical applications are: 1. Acts as moving standing valve to minimize dry runs while reducing tubing wear. 2. Will continually operate in transition area; Lizard will move the to transition flow area to deliver ball to lifting sleeve, unloading wells and work itself to the bottom. 3. Increase lifting depth from 40 degrees to 75 degrees. 4. Stop yo-yo effect between two-piece plungers. A Lizard assembly for a plunger lift system is used to remove fluids and hydrocarbons from a subterranean wellbore includes a ball lifting sleeve meant to act as bumper spring or sit on bumper spring that engages (e.g., unites) and disengages with plunger assembly. The sleeve acts as an orifice to capture hydrocarbons from dead space around bumper spring and centrally force hydrocarbons to plunger assembly with maximum velocity. The ball lifting sleeve provides transfer of ball and liquid column to lifting plunger and assists in transitioning flow area. The sleeve provides softer fall rates reducing damage to lifting plunger and bumper spring. The Lizard assembly provides higher quality plunger operation further down curvature of deviated and horizontal wellbores providing deeper lifting capabilities. The sleeve provides standing valve principles to horizontal and vertical wellbores. The Lizard will unload high volume liquid loads by acting as a movable standing valve and gradually working its way to bumper spring. The Lizard can be utilized to replace bumper springs, reducing tubing restrictions downhole.

Presented by:

Sabrina Sullivan, Arthur Sullivan, and Ron Elkins 
Plungers and More

 

Artificial Lift
Room 104
(08) Sand Control Management in ESP Case Studies Delaware Basin
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This paper proposes an analytical methodology that consists of an evaluation of the particle size distribution, viability for the use of sand screens and centrifugal separation systems for sand control management in wells with high sand and fluid production producing through an ESP. All the technical considerations are explained focusing on the information required and the parameters analyzed to recommend the most accurate design for sand control; selected approaches and models that have been developed to improve the runtime due to sand issues. The methodology for the evaluation and selection of sand control systems was proven in a field with historical low run time due to sand problems in the ESPs. The methodology is explained with the theoretical concepts and through several case studies in the Permian Basin.
 

Presented by:

Gustavo Gonzalez, Luis Guanacas, Scott Vestal, Odessa Separators Inc.

 

Artificial Lift
Room 106
(03) Harmonic Mitigation Challenges in Unconventional ESP Applications
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Harmonic Mitigation Challenges in Unconventional ESP Applications 1. OBJECTIVES/SCOPE: Modern oil field producers face increasing pressure from utilities regarding harmonic compliance, and harmonic-related penalties can be severe. A more effective approach for mitigating VSD-induced power harmonics is presented, in which the unique electrical requirements of unconventional ESP applications are considered. The results of a field study demonstrate how a unique application of passive filter technology is far superior (both in technical performance and cost/benefit to the customer) when compared to outdated 12,18,24 pulse drive architectures and even AFE technology. 2. METHODS, PROCEDURES, PROCESS: Ensuring optimal harmonic reduction for VSD/ESP applications requires a more comprehensive approach, as well as a new application of established technology and new monitoring methods. Historical load analysis, field survey data (direct harmonic measurements), and consideration of future electrical loading changes must all be taken into account in a successful project. Moreover, verifying harmonic mitigation compliance in line with applicable standards requires new measurement methods, technologies, and planning. 3. RESULTS, OBSERVATIONS, CONCLUSIONS By focusing on field-scale harmonic reduction as opposed to performance at individual well sites, a better outcome for the customer and the supplying utility can be achieved. A field harmonics study encompassing 22 individual well sites is presented and harmonic current distortion reduction results out-perform utility requirements. Comparisons of various mitigation topologies are presented as they relate to the unique challenges of steep production decline applications, as well as challenging modern oilfield power quality environments. A new passive harmonic mitigation architecture is presented that adapts to changing electrical load, ensuring harmonic reduction is optimized as electrical loading declines. In addition, harmonic measurement methods and monitoring are discussed as they relate to recent changes in IEEE and IEC standard requirements and as an effective means of managing the routine maintenance requirements of passive harmonic filters. 4. NOVEL/ADDITIVE INFORMATION This paper will present realistic considerations and examples of real world results for the specifying engineer, when considering harmonic mitigation technology in unconventional VSD/ESP applications. In addition, new methods of employing remote power quality monitoring are presented which can prove invaluable to continued, reliable operation and compliance with applicable standards.

Presented by:

Ryan Dodson and  Davi Lacerda
Champion X
 

Artificial Lift
Room 107
(13) Early Application of Plungers in Gas Wells Producing Liquids
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It is recognized in the industry that it is wise to have AL in place before liquid loading is expected for a number of reasons.  These reasons include no production loss when the well drops below critical, convenience as the rig may/may not be available when the well drops below critical later, and in some cases some uplift is observed when installing plunger other AL before the rate drops below a calculated predicted critical. The discussion here concerns installing plunger lift in deviated wells in advance of predictions from well-known methods that say the well is not liquid loaded. However loading and significant uplifts in production are still observed with plunger contrary to what should be expected from commonly used industry indictors.  Some explanations are offered concerning the cases. The results should be of interest to operators that may experience the same situation/s.
 

Presented by:

Mark Gose Billy Hood, Elizabeth Clem and Andrew Borgan, BKV Artificial Lift
James F. Lea, PLTech, LLC

 

Artificial Lift
Room 110
(33) New Gas Bypass System for Unconventional Wells on ESP
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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.  
 

Presented by:

Kimberly Selman and Matt Raglin
WellWorx Energy

 

Artificial Lift