2019 Southwestern Petroleum Short Course Schedule

Wednesday, April 17th

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

Room 101
(2019039) ANALYSIS AND OPTIMIZATION OF SUCKER-ROD PUMP DESIGN
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Rod lift design methods remain overwhelmingly unchanged since the mid-20th century. Meanwhile, drilling and completion technology has undergone a dramatic transformation. The innovation gap between the two technologies and low-flow artificial lift has resulted in the need for improved design and workflow methods to more effectively operate an unconventional well throughout its lifecycle. New design and workflow processes have been developed that improve upon today’s common practices through the observation of unconventional well characteristics and root cause analysis of equipment failure. This new design and workflow process has resulted in improved performance for unconventional wells in the Permian Basin.

Presented by:

Levins Thompson, Zack Smith and Ricky Roderick
Don-Nan Pump and Supply

Artificial Lift
Room 102
(2019046) DYNAMIC FILTRATION TEST EXPERIMENTS DESIGN
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The purpose of this project is to conduct a Dynamic Filtration Test to Investigate the Effect of Preformed Particle Gels (PPGs) on Un-swept, Low-Permeable Zones/Areas. A filtration test is a simple means of evaluating formation damage. This work use schematically dynamic filtration test experiment design apparatus to carry out the various filtration test experiments. It use different core samples, various brine concentration, and various gel types.  The permeability   of each sandstone core samples is calculated before and after the filtration test. Experiments are still being observed.  The objective of this study is to find methods that minimized the damage caused by PPGs on un-swept, low-permeable zones/areas, thus improving PPG treatment efficiency. This approach will identify the best properties of the PPGs, which can neither penetrate conventional solid rocks nor form cakes on the rocks’ surface. 
 

Presented by:

Mahmoud Elsharafi, Jenom Pyeng , Tapiwa Gasseler, and Jedeshkeran Chandraseqaran
Midwestern State University

General Interest
Room 103
(2019054) COMPARATIVE STUDY OF WELL SOAKING TIMING (PRE VS. POST FLOWBACK) FOR WATER BLOCK REMOVAL FROM MATRIX-FRACTURE INTERFACE
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Water block after hydraulic fracturing is one of the major challenges in shale oil recovery which affects the optimal production from the reservoir. The water blockage represents a higher water saturation near the matrix-fracture interface, which decreases the hydrocarbon relative permeability. The removal of water blockage in the field is typically carried out by soaking the well (i.e., shut-in) after hydraulic fracturing. This soaking period allows water redistribution, which decreases the water saturation near the matrix-fracture interface. However, previous field reports show that there is not a strong consensus on whether shut-in is beneficial in term of production rate or ultimate recovery. Due to the large number of parameters involved in hydraulic fracturing and tight formations, it is challenging to select which parameter plays the dominant role in determining the shut-in performance. Furthermore, literature on field case studies does not frequently report the parameters which are of researchers’ interest. In other words, the challenge of evaluating shut-in performance not only lies on the complexity of parameters and effects involved within the reservoir, but also the limited number of field case studies which report a comprehensive list of fracturing and reservoir parameters.


This paper aims to investigate the effect of well soaking timing on shut-in performance. This question is motivated by the fact that in the field, shut-in can take place either immediately after hydraulic fracturing but before the first flowback (i.e., pre-flowback) or sometime after the first flowback (i.e., post-flowback). The timing of shut-in is believed to influence the production performance, because it dictates how much water will imbibe from the fractures. A numerical core-scale model is built and validated by a successful history match with numerous experimental data. Our model demonstrates that shut-in performed after the first flowback (i.e., post-flowback) can help ensure a higher regained oil relative permeability than shut-in performed before the first flowback (i.e., pre-flowback). A discussion on the water blockage mitigation from these two shut-in timings is also presented. As a result, this study proposes that flowback should be carried out immediately following hydraulic fracturing, even if an extended shut-in is to be performed later.

Presented by:

Nur Wijaya, Texas Tech University

Reservoir Operation
Room 104
(2019013) THE ECONOMIC TRADEOFFS IN DEVIATING WELLS TO PRODUCE FROM DOWNHOLE LOCATIONS THAT EXACTLY COMPLETE INJECTION PATTERNS
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In today’s world it can be challenging to locate the downhole well location immediately below the surface location in secondary and tertiary projects. There are several factors that must be considered when picking the surface location that will maximize value including 1) increases cost of building a location and drilling, 2) increases cost of artificial lift and operations, and 3) production rate and reserve impact.  This paper will explore how these factors can be put in an Excel Spread Sheet to assist in picking the location that will maximize value. 

Presented by:

Steve Gault, Erileck Cameron, Joe Johsnon, Sebastian Millan, Ryan Owen and  Calvin Stewart
OXY USA, Inc.

Artificial Lift
Room 106
(2019020) INNOVATIVE PACKER TYPE GAS SEPARATOR:  OPERATING PRINCIPLES AND DESIGN CRITERIA
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Wells with high depletion rate present high free gas at pump intake conditions. In all cases, the production of fluid with a high gas-liquid ratio leads to an inefficient performance of the rod pump systems. The initial solution to this problem is the installation of poor boy gas separators which capacity of gas separation is reduced and do not provide a high-performance solution.  Packer type gas separators are the most efficient downhole separators in the market, however, they usually have some operational limitations. This paper summarizes a new design of the packer type gas separator which uses more methods of separation than the traditional design and can be designed based on the conditions of each well overcoming the typical limitations. The design criteria are reviewed, and some operational guidelines are listed to reach the best performance in each application for gas separation.

Presented by:

Gustavo Gonzalez, Shivani Vyas, Luis Guanacas Neil Johnson
Odessa Separator Inc.

Artificial Lift
Room 107
(2019016) SUCKER ROD GUIDE IMPROVEMENTS
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Typically, the Petroleum Industry maintains operational ideas that were developed years ago.  These operational ideas may still have merit, but some improvements should be considered.  Sucker rod guides are an example of such practices.  Most production companies continue to use rod guide material that was introduced at the conception of the recognition of the need for sucker rod guides.  This presentation will give information of new materials and new application ideas for sucker rods guides. 

Presented by:

Calvin Stewart,  Stephen Borcik and Steve Gault
OXY USA Inc.

Artificial Lift
Room 108
(2019034) IRIS: A NEW ERA IN DOWNHOLE DATA TREATMENT
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When optimizing a reciprocating rod lift installation, key control parameters must be extracted from the downhole data. Traditionally, downhole data in the form of position and load data is derived from surface data using the wave equation. Downhole position and load data must be carefully analyzed to extract key control parameters for reciprocating rod lift optimization.
IRIS introduces a new and innovative approach for downhole data analysis.


Through a change in coordinate system, IRIS transforms downhole position and load data into polar coordinates. This change in coordinates creates three new data sets, which greatly simplify the extraction of the above mentioned key control parameters.
Additionally, IRIS can be used to manage both viscous and mechanical friction through an extra friction detection algorithm and a viscous damping estimator.


In this paper, the IRIS algorithms and results are presented.
 

Presented by:

Victoria Pons, Baker Hughes, A GE Company

Artificial Lift
Room 110
(2019008) FIELD-DRIVEN INITIATIVE TO IMPROVE ARTIFICIAL LIFT EFFICIENCY AND RELIABILITY WITH AN ENGINEERED SUCKER ROD PUMP BALL VALVE INSERT
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To increase recovery rates – the greatest challenge facing the industry – operators must not only look to step-change technologies, but improvements to existing technology. Even incremental increases in recovery rates can impact economics when multiplied across numerous wells. For example, approximately two-thirds of onshore wells use beam operated pump jacks with reciprocating rod pumps. Our objective was to improve the efficiency and reliability of sucker pumps by engineering a new ball valve insert.  Prototype testing demonstrated that the lowest pressure drop was provided by an insert design with the tangent angle equal to Pi (3.14, π), as it forced the fluid into a vortex spin. Based on a number of flow rates (including two phase flow) the TangentFlow Insert decreased pressure drop by 40% on average resulting in 58% more flow than the bar-bottom inserts. In addition, compared to the bar-bottom inserts, which produced significant ball chatter, the TangentFlow Insert had a consistently low decibel reading with increasing flow rates, as the ball remained stationary. This results in reduced gas breakout, which in turn further reduces pressure drop, fluid pound and pump damage.  One-year field results from 50 wells in the Red River reservoir of Montana and North Dakota demonstrate that the TangentFlow Insert reduced pressure drop across both the standing and traveling valves to increase average surface flow by 8%. Considering the average water to oil ratio in the area, this provides an additional 3.1 bbl/day/well. This increase applied over 50 wells translates to approximately 54,603 bbl/year, or $3.33MM in revenue at current oil prices.  The design of the TangentFlow Insert improves the efficiency and reliability of sucker rod pumps by minimizing the effects of pressure drop, gas breakout, solids accumulation (wax), casing wear and ball wear, which together improve pump efficiency and production flow. Because the design enables the ball to remain stationary, smaller and lighter balls can be used, allowing for higher flowback solids and reduced cage wear, respectively. The TangentFlow Insert is manufactured to replace conventional bar-bottom inserts without needing to change out the entire pump assembly, making them applicable to 90% of pumps presently used in the industry.

Presented by:

Corbin Coyes, TangentFlow Inc.

Artificial Lift
Room 111
(2019048) IMPACT OF PRODUCED WATER ON THE CORROSION OF STEEL BY CHLORINE DIOXIDE
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The perceived impact of chlorine dioxide (ClO2) on the corrosion of steel used in the oil patch has been a controversial issue for many years.   Although a few studies on this issue have been published, those results have been contradictory. As concerns surrounding this issue continue to be raised, a systematic study has been undertaken to understand the corrosive effects of ClO2 towards steel in various produced waters.  Research shows that the baseline corrosion rate of untreated produced water is related to TDS, with other factors being involved, such as the presence of H2S and iron. This paper summarizes the results of other studies that have been done, and demonstrates the contradictory nature of such studies. The results of this on-going study show the relationship between the TDS of produced water and corrosion resulting from use of varying concentrations of ClO2.  The paper explains the contradictory nature of corrosion caused by ClO2.

Presented by:

Greg Simpson, Purleline Treatment Systems

General Interest

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

Room 102
(2019040) MAXIMIZING PRODUCTION EFFICIENCY IN BEAM PUMP WELLS USING ROD GUIDE DESIGN OPTIMIZATION
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There are many challenges associated with sucker rod lift in deviated wellbores that can lead to high failure rates and lost production. Tubing failures are amongst the costliest workovers and are often a result of metal to metal contact between the rod coupling and the tubing. Evaluating tubing on-site using both gamma and electromagnetic inspection allows for proper design optimization before returning to production. The tubing scan can be aligned with deviation data, previous rod design, and failure history to adjust the string design to effectively extend mean time between failures and improve asset value. An effective rod guide strategy was developed to mitigate tubing wear using proper guide type, material, and placement. The implementation of this strategy has helped to maximize production efficiency across the asset. 

Presented by:

Brian Wagner, NOV Tuboscope

Artificial Lift
Room 103
(2019053) EFFECTIVENESS OF HIGH VISCOSITY FRICTION REDUCERS IN PERMIAN WELL COMPLETIONS
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Friction reducer is a hydraulic fracturing fluid additive meant to lower costs by decreasing the friction pressure in tubulars during pumping operations. High viscosity friction reducers (HVFRs) have become increasingly popular in well stimulation applications in lieu of conventional slick water fluid systems involving linear and cross-linked gels. However, various factors must be considered when assessing the effectiveness of using HVFRs under certain frac operation conditions. This paper aims to evaluate how effective of a solution HVFRs are while determining the optimal operating conditions for this additive.

Presented by:

Omar Zeinuddin, Texas Tech University

Well Completion and Simulation
Room 104
(2019043) APPLICATION OF WATER TREATMENT PROGRAMS TO PREVENT FOULING AND CORROSION DURING DRILL-OUT
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Case study of mill-out operations in the Permian Basin which evaluate chemical program and processes used. Results show how existing processes and chemicals used or lack thereof, can affect equipment and undo the preventative chemical treatments used during the hydraulic fracturing process. The study looks at field water testing performed during various mill-out operations and considered workover rig vs coiled tubing, equipment set up, water & chemicals used, and operational challenges. Water analyses were completed on injection water and returns at various interval of the mill-out. Effectiveness of chemical treatment was also monitored when biocide was used. Four field case studies are presented for horizontal wells. Two wells were milled-out utilizing workover rigs and two wells were completed using coiled tubing. Testing results show the impact of equipment setup and operations process on the water quality and efficiency of the chemicals used. Water fouling was prevalent in all cases, with coiled tubing jobs showing the highest degree of water contamination and chemical inefficiency. Changes in water treatment program during operations showed significant improvement and sustainable results. Potential corrosion of the work string due to water fouling and composition was also observed, and the effects of changes in chemicals were monitored. This is important because it identified operational improvements that can reduce equipment replacement costs, chemical overuse and protect wells from fouling due to high bacteria. This case study provides a comprehensive review of mill-out operations and provides guidelines for improving chemical efficiency and potential of  extending life of the work string.
 

Presented by:

Tanhee Galindo, GeoKimika Oil & Gas

Drilling Operations
Room 106
(2019023) ENERGY SAVINGS ON BEAM PUMP SUCKER ROD SYSTEMS / CONTROL SOLUTIONS WITH FIELD CASE STUDIES
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One of the largest lease operating expenses is electrical cost. Only a small portion of electrical cost is value-added conversion of electricity to fluid lifting power. The rest is lost to downhole friction, fluid flow friction, pumping unit, and electrical to mechanical power conversion inefficiencies.  Overall “line to fluid” system efficiency will typically range from 20% to 40%. Some cases will be as low as 10%.

Some of those energy losses are inevitable.  Some can be reduced through improved operation and controls. This paper will present power studies of various control schemes on actual wells, highlighting the best solutions for reducing power consumption. 

The study will examine: line starters with timers, line starters with pump off controllers, pump off controllers with variable speed drives and advanced embedded controllers. Electrical average voltage(V), power factor, maximum current(A), average current(A), total apparent power(KVA), total reactive power(KVAR) and total real power(KW) will be show for each variation. Apparent costs and ROI of implementing and/or changing to a new control system will be presented.    

Presented by:

Jordan Hanson, Control Solutions

Unico

Hy-Bon/EDI

Artificial Lift
Room 107
(2019004) ROD PUMP CLEARANCE GUIDANCE
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Slippage is required for lubricating the plunger/barrel within beam pumping systems. Increasing pump clearance increases the amount of slippage, which may lead to inefficient operations. Operators could run their field more efficiently through decreasing failure rate and increased electrical cost savings by calculating the optimum design using the Patterson Slippage equation for individual well conditions. This paper will discuss the economic tradeoffs with changing pump clearances and recommend theoretical optimum designs given well conditions. The paper will also include nomographs and a calculator to recommend optimum designs. 

Presented by:

Stephen Borcik  and Steve Gault, OXY USA, Inc.
Lynn Rowlan, Echometer Company

Artificial Lift
Room 108
(2019006) VALIDATION OF FRICTION COEFFICIENT AND WEAR CONCEPTS IN SUCKER ROD LIFT SYSTEMS
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In some of today’s unconventional wells, sucker rod pumping systems are facing challenges related to excessive wear, affecting production and increasing operational costs. One of the reoccurring damages in a sucker rod pumped well occurs near the kick-off point in a deviated well between the coupling and the tubing or between the sucker rod and the tubing; the metal-to-metal contact causes hole-in-tubing failures and operators have been seeking solutions to mitigate or minimize excessive tubing wear in highly deviated wells. Wear caused by both metal contact and abrasive particles, as well as corrosive attack from the wellbore’s fluid also affects the metal integrity of the tubing, coupling and sucker rod. It is beneficial to develop fundamental understanding on wear and friction concepts in rod lift applications, to optimize rod lift product designs and improve Mean Time Between Failures (MTBF) in deviated wells.

In this paper, the concepts of friction and wear will be explained from applied rod lift engineering perspective. Field tested solutions to reduce tubing wear will be presented with lab and field data.

Presented by:

Wanru Shang, Pablo E. Barajas and Reza Eghtesad
Apergy Rod Lift

Artificial Lift
Room 110
(2019011) OPTIMIZING SHUTIN TIME FOR PUMP-OFF CONTROLLERS
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Much work has been done on the operation of beam pump pump-off controllers, but the downtime is normally a simple timer and the optimum downtime is usually set by rule of thumb or trial and error. This paper uses a complete well model coupled with a transient reservoir  model to show that the optimum downtime in terms of total energy used per produced barrel of oil is equal to the wellbore storage time from well test analysis.

Presented by:

Walter Fair, InterAmerican Petroleum Consultants

Artificial Lift
Room 111
(2019042 MANIPULATING CASING PRESSURE TO BETTER HANDLE GAS IN CERTAIN WELL TYPES
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Rod pumps are not the ideal system of lift when it comes to handling gas. We can only do so much with the configuration downhole especially for wells with open hole completions. Despite the limited options, we are coming to find that we can do better by manipulating parameters at the surface. Historically, we have manipulated back pressure on the tubing in order to control when gas breaks out of solution in the tubing. Now we are finding, on certain well types, that manipulating back pressure on the casing in order to keep gas in solution through the pump is proving to be successful. By doing this, we are seeing beam wells that now face less equipment stress due to gas interference, more consistent, stable run time and production on a daily basis, and even optimized inflow where production increases for wells. 

Presented by:

Blake Whittington, OXY USA Inc.

Artificial Lift

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

Room 101
(2019051) MAXIMIZE YOUR WELLBORE PRODUCTIVITY AND EUR USING THE EXCITE PIN-POINT REFRAC SYSTEM
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Comitt Well Solutions’ Excite system is an innovative down hole tool specially designed for pin-point refracturing and re-stimulation applications. The system is fully hydraulic and can accommodate any space-out between its isolation packers. The patented technology treats each cluster in the wellbore in a single trip and allows treatment of both existing and newly added stages. Since the first successful field trial in 2017, the Excite system has been used in acid stimulation, proppant refrac, revitalization of SWD wells, leak detection, repairing of frac hit damage and many other applications. With average production uplift of 2-10 times post treatment and payout as low as 30 days, clients are seeing a great return on their investment. 

Presented by:

Brad Holmes and Shanshan McNeill
Comitt Well Solutions

Well Completion and Simulation
Room 102
(2019032) DEVELOPMENT OF A ROD GUIDE MODEL WHICH GENERATES A MINIMUM LEVEL OF TURBULENCE, PERFORMING CFD ANALYSIS AND HYDRODYNAMIC COMPARISONS BETWEEN DIFFERENT GUIDE DESIGNS
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A hydrodynamic analysis for different rod guide designs simulating downhole fluid conditions was made using computational fluid dynamics (CFD) analysis, which is widely used for solving the partial differential equations of fluid motion by discrete approximation.  A particular turbulence kinetic energy graphic for each guide sample was created and compared to each other. The results shows a significant difference between the samples and the new rod guide design with conclusive proof of a better hydrodynamic performance. 

Presented by:

Ricardo Padron, Tenaris

Artificial Lift
Room 103
(2019050) REPLACING BRIDGE PLUGS CAN LEAD TO COST SAVINGS AND INCREASED PRODUCTION
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Replacing bridge plugs with Perf PODs, to plug/divert individual perforations, allows Operators to divert the stimulation mid-stage and reduce the total number of bridge plugs within a wellbore while maintaining the advantages of closer stage spacing and adding additional clusters.  The risk of a pre-set plug can be drastically reduced, along with pump down time, completion cost and resources associated for the corresponding wireline runs and subsequent millout work.  Applying Perf POD diversion technology between bridge plugs allows the Operator to achieve maximum cluster efficiency, while stimulating the entire stage, without leaving orphan clusters behind.  This ensures a more consistent stimulation volume pumped into each perforation cluster, ultimately providing a more balanced treatment and reducing the probability of a “runway frac”, which could potentially damage offset wells.   


Based on current stimulation design - are you effectively stimulating every cluster?
 

Presented by:

Jenna Robertson, Thru Tubing Solutions

Prod. Handling
Room 104
(2019003) EVALUATION OF C GRADE RODS AND T COUPLING USAGE IN SAN ANDRES CONVENTIONAL
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In 2016, a recommendation was made in EOR to begin utilizing Grade “C” when replacing rods in San Andres wells or wells less than 5,000’ deep. The advantage of the Grade “C” rods believed to be better corrosion resistance, tubing leak reduction, and lower material cost. It was also recommended that “T” coupling be considered as an alternative to Spray Metal (“SM”) couplings as they are softer and should fail preferentially to the tubing. As with any technology that is new to the field in question there is concern about wide spread use until sufficient data is gathered on a smaller subset of wells to prove up the concept. As failure frequency is a key metric when evaluating artificial lift performance, and it can take several years to develop sufficient data, an analysis method needed to be utilized to track the equipment performance over a shorter duration so that use can be expanded as early as possible. This was accomplished by developing statistical data for sucker rod and coupling installations and failures over a specific time period comparing the failure rate of the “C” rods and “T” couplings versus the “KD” rods and “SM” couplings that are typically run. The analysis showed that the “C” grade rods and “SM” couplings were not showing an increased failure rate and therefore provided support to start expanding their use in EOR, which should result in significant cost savings. To further understand the corrosion differences between C-Rods and KD-Rods corrosion coupons were constructed from sections of actual rods and placed in several wells of varying characteristics. This paper will also present the findings from this corrosion test, which is currently nearing completion. 

Presented by:

Garrett Best, Steven Reedy, Calvin Stewart and Steve Gault
OXY USA, Inc.

Artificial Lift
Room 106
(2019041) A SUCCESSFUL BAKKEN FAILURE REDUCTION PROGRAM
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Oasis Petroleum has ~1000 rod pump wells in the Bakken producing from 8000’ - 10,000’. A focused effort has been made over the past few years to reduce the failure rate from ~1.0 failures/well/year to the current rate of .68 failures/well/year. This has been the result of a holistic approach which has encompassed improvements in rod design, surveillance, training, development of Standard Operating Procedures and Best Practices, trialing new technology and POC optimization. This paper will document some of the successes and failures during this journey.

Presented by:

Will Whitley, Matt Chapin, Lauren Coles and Karla Traweek 
Oasis Petroleum

Artificial Lift
Room 107
(2019015) SHOOTING FLUID LEVELS IN CO2 APPLICATIONS
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In 2014 Oxy EOR had lost confidence in the accuracy of Fluid Levels in CO2 wells and was not shooting them. Echometer and Oxy collaborated to identify the root cause of the fluid level inaccuracy and resolve the issue through improved procedures and educating personnel. Today trusted fluid level information adds value by improved operational decision making. 

Presented by:

Erilck Cameron , Joe Johnson, Sebastian Millan Ryan Owen, Calvin Stewart and Steve Gault,  OXY USA, Inc.
Lynn Rowlan, Echometer Company

Artificial Lift
Room 108
(2019026) CASE STUDY - USE OF CAPILLARY STRING ASSISTED ARTIFICIAL LIFT AT THE ADAIR SAN ANDRES UNIT
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The Apache-operated Adair San Andres Unit (ASAU) currently employs fifteen capillary string (cap string) equipped producing wells, representing 16% of the active producer count. Apache started converting producing wells to cap strings in 2016.  This idea was introduced to Apache at the 2012 CO2 Conference in Midland and later reinforced during a field tour of Whiting’s North Ward Estes CO2 flood in 2015.  The chief benefit using a cap string is production stability.  A review of these installations 
is categorized by a reduction in production variance, meaning an increase in stability - be it oil and gas production, or water-oil and gas-liquid ratio (GLR).  This equates to less rig intervention, more uptime.  Of note: 1) a cap string will successfully operate below the minimum GLR of 400 SCF/BBL/1000’ required by plunger lift, 2) conversion to cap string assisted lift is not affected by the wellbore geometry, and 3) ASAU installations are packer-less.

Presented by:

Rebecca Larkin and Joe Lopez
Apache Corp.

Artificial Lift
Room 111
(2019030) HIGH RATE UNCONVENTIONAL GAS LIFT
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The purpose of this paper is to discuss the history of different gas lift design methods and the theory behind a new design method.  In January 2019, Production Lift Companies and Concho Resources ran a new gas lift design method in two unconventional wells in the Permian Basin.  This new method is designed to exploit the initial high bottom hole pressure in unconventional wells to produce higher rates that, before now, were only possible with an ESP.  This life of well design will also follow the well’s decline and efficiently produce the well at lower rates.  When completed correctly, the well can be switched to PAGL, Plunger Lift or GAPL without pulling the tubing.  

The traditional gas lift design method for unconventional wells is to run unloading valves until you reach a minimum spacing of 500’ (Fig. 1) and then continue the 500’ spacing to the packer.  The 500’ spacing was adopted by the industry in the late 80’s as “Best Practice” and has remained the standard today. 
 

Presented by:

Jay Miller, Production Lift Companies
Kenneth Estrada, Concho

Artificial Lift

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

Room 101
(2019052) MAXIMIZE YOUR WELLBORE PRODUCTIVITY AND EUR USING THE EXCITE PIN-POINT REFRAC SYSTEM
More Information

Comitt Well Solutions’ Excite system is an innovative down hole tool specially designed for pin-point refracturing and re-stimulation applications. The system is fully hydraulic and can accommodate any space-out between its isolation packers. The patented technology treats each cluster in the wellbore in a single trip and allows treatment of both existing and newly added stages. Since the first successful field trial in 2017, the Excite system has been used in acid stimulation, proppant refrac, revitalization of SWD wells, leak detection, repairing of frac hit damage and many other applications. With average production uplift of 2-10 times post treatment and payout as low as 30 days, clients are seeing a great return on their investment. 

Presented by:

Brad Holmes and Shanshan McNeill
Comitt Well Solutions

Artificial Lift
Room 103
(2019049) DATA-DRIVEN PROGNOSTIC METHOD FOR EQUIPMENT IN OIL AND GAS INDUSTRY
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Catastrophic accidents in offshore drilling operations have greatly endangered human lives, environment and capital assets. Although risks in offshore oil and gas operations cannot be completely eliminated, a substantial amount of risks can be minimized through preventive and mitigative measures. A key aspect of the offshore drilling risk is the reliability of drilling systems. According to the World Offshore Accident Dataset and many other investigations, the overwhelming majority of disastrous accidents in offshore drilling operations were caused by equipment failures and human errors. The capabilities to predict the lifetime and provide early and effective warnings in real time are crucial to ensure reliable and safe offshore operations. The objective of this research is to mitigate offshore drilling risks by developing a scientific framework for data-driven failure prognosis for complex drilling systems operating in heterogeneous and extremely harsh environments. A novel data-driven reliability model in conjunction with a systems and economic impact analysis is developed integrating multi-source (e.g., operations and maintenance records, in-situ monitoring data) and multi-modal (e.g., lifetime data, degradation profiles) data. Numerical cases studies will be presented to demonstrate the proposed method. 
 

Presented by:

Yisha Xiang, Mario Beruvides and Lloyd Heinze
Texas Tech University

General Interest
Room 104
(2019017) DOWNHOLE EQUIPMENT REPLACEMENT GUIDELINES
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In 2017 and 2018 Oxy EOR conducted a series of RCFA schools. As part of these schools, information was gathered on the range of equipment replacement for failure types. In 2018, a cross functional team of experienced stakeholders vetted this information and compiled a list of equipment replacement guidelines. This paper will share these guidelines. 

Presented by:

Steve Reed, Calvin Stewart, Steve Gault, Saul Tovar, Joel Gallegos and Rynn Peeler
OXY USA Inc.

Artificial Lift
Room 106
(2019018) ITS ALL ABOUT THE END FITTING 3: PRESSURE DROP, EXTRA CORROSION CAPABILITY, COMPRESSION HANDLING
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As fluctuations in oil price continue, the industry has changed and is demanding improvements from each method of artificial lift. Required flow rates are increasing due to the longer laterals of new horizontal wells being added to inventory. Rod Lift is not immune and is being asked to enter the artificial lift cycle earlier and support the pumping of wellbores with added complexities due to geometries and/or production demands. The fiber reinforced plastic (fiberglass, FSR) rod continues to meet the ever-increasing demand and complexities. The two previous editions of ‘IT’S ALL ABOUT THE END FITTING’ focused on the design of the new generation of fiberglass rod, the added strength the industry has requested, the benefits regarding the handling of compression and methods to mitigate uncertainties of the wellbore dynamics. This edition will focus on benefits of the latest generation of the end fitting. It will explain how a new configuration of the wedge profile provides reduced pressure drop at each connection and/or adds corrosion resilience. The new wedge profile also increases the ability of the end fitting to handle compression. Data will be provided in support of increased production. The fiberglass rods have been delivering benefits for the last 30+ years to the industry and continue to maintain pace with growing demands of artificial lift through innovation and development of new generation FSRs. With an ongoing progress of FSR technology the glass rods are being adopted earlier in the well’s life cycle requiring us to make the product RUN LONGER & PRODUCE 

Presented by:

Ryan Gernentz, Karol Hricisak and Alex Booth
Endurance Lift Solutions

Artificial Lift
Room 107
(2019036) DETERMINING OPTIMIZED GAS INJECTION RATE FOR GAS LIFTED WELLS TO MAXIMIZE LIFT EFFICIENCY
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Problem being addressed: Determining optimized Gas Injection Rate for Gas Lifted wells to maximize lift efficiency. Challenges: While Gas Lift is the most natural artificial lift method, ever-changing surface and downhole conditions cause significant inefficiencies. The changing conditions require frequent adjustments to surface-injected gas rates to maintain the most efficient lifting gradient. If the proper adjustments are not made, these inefficiencies may hinder production and increase lease operating expenses. Solution: By using Apergy’s proprietary hunting algorithm, Bloodhound, optimal gas injections rates are determined by the magnitude in the bottom hole pressure drawdown, with use of a permeant down hole gauge. Through continuous and proportional rate adjustment, the Bloodhound algorithm learns from previous set point deltas and tests against the inferred optimal rate, as well as changing conditions. Results: In under-injection scenarios, Bloodhound can accelerate the recovery of oil by up to 10 percent, regardless of the well’s position on its natural decline. In over-injecting scenarios, wells can maintain oil production rates while using up to 50 percent lift gas. Both results can be successfully achieved with few engineering hours, manually calculating or modeling well performance curves to determine inferred optimal rate. 
 

Presented by:

Dustin Sandidge, Apergy

Artificial Lift
Room 108
(2019007) SAND FLUSH PLUNGER PERFORMANCE IN THE HWY 80 FIELD UPDATE
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The performance of Harbison-Fischer’s patented Sand Flush Plunger (SFP) was assessed relative to the average runtime for standard API plungers in the HWY 80 field, operated by Pioneer Natural Resources (PNR). The field case study captured information from pump-tracker for 5,283 wells and 32,804 workover records dating back to 1989. As of the record date 1,934 different wells had used a SFP 3,473 times. The analysis, however, focused in 194 wells for each of whom the data showed at least 1 failure originated by the pump for each of the two plunger types. The average runtime for the SFP and the API plungers were found to be 1,178 days and 579 days, respectively.

The present study constitutes an update on the continuous monitoring of the performance of the SFP that has been carried out in HWY 80 field since 2015. The average runtime for the SFP was reduced in 119 days whereas the average runtime for the API pumps increased by 36 days. The number of wells considered for calculating the average runtimes has gone up by 37 wells from 157 reported in 2015. Similarly, the number of qualifying pump changes has increase by 102 from 486 reported back in 2015. The data processing has been carried out using Tableau, and slightly different criterions for cleaning the records have been implemented compared to the paper presented in 2015 at this same conference.

Presented by:

Felipe Correa, Apergy - Harbison-Fischer

Artificial Lift
Room 111
(2019001) ANNULAR GAS LIFT IN THE DELAWARE BASIN
More Information

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

Presented by:

Kale Baker, Anadarko
 

Artificial Lift

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

Room 101
(2019031) UNDERSTANDING CAVITATION ON HYDRAULIC JET PUMPS, A SOLID AND EASY TO IMPLEMENT GUIDELINE TO AVOID AND MITIGATE CAVITATION DAMAGE
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The cavitation phenomenon has been extensively studied for many years, however, guidelines on how to implement this existing knowledge to the actual operation of the jet pumping systems in the oilfield are not abundant and, as per the author can see it, not yet being presented in such way that the people that operate these systems in the oilfield could implement on a straight forward way. It has been proven that using a scientific and easy to follow methodology, it is possible to prevent jet pump operating problems related to cavitation, during the early, middle and late stage of the well production life. Preventative and Corrective methodologies are based on: Measured production rates, power fluid rate and pressure, gas to liquid ratio, jet pump seating depth and jet pump nozzle/throat combination.

This paper presents a straight forward discussion on the jet pump cavitation, its hydrodynamics, causes, identification, potential damage, consequences on the jet pump performance and methods to predict it and avoid it.

Presented by:

Osman A. Nunez-Pino, Liberty Lift Solutions LLC

Artificial Lift
Room 102
(2019047) AN ENCONOMIC AND RISK BASED APPROACH TO OFFSET WELL PREPARATION FOR NEARBY FRACS IN THE DELAWARE BASIN
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With the increase in activity in the Delaware Basin, preparing wells for the pressure spikes seen from offset fracs is crucial in order to maintain safe operations.  It is important to take risk and economics into account when deciding how to prep a well. Most importantly, historical data should be factored into the decision making process and used to build the program guidelines.  Factors that should be accounted for are artificial lift type, surface equipment ratings, producing interval, frac azimuth, and 
relative distance and position to the well being fractured.
 

Presented by:

Ryckur Shuttler and Daniel Benavides
Anadarko Petroleum

General Interest
Room 103
(2019045) ENERGY FROM SALTWATER MUD
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There is a growing need for energy throughout the world and this increase in demand for energy has now also put a strain on the current sources of energy. In the process of oil/gas production, there are large amounts of water released into the atmosphere as well as into the ground or soil. This water contains chemicals such as Sulphur and Nitrogen oxides, Bitumen, Calcium, Base oil, and Sodium. It is commonly referred to as “wastewater” and is disposed of. The goal of this project is to investigate the possibility of acquiring energy from this wastewater. This is can be done by using various types of soils and water. Various mixtures were created using soils mixed with different percentages of clay and water with varying salinity. A small source of electricity was then applied to the saltwater mud to provide a voltage to the experiment. The chemicals in the mud are then expected to amplify the input voltage and create enough energy to power electrical devices. To prove this, a bulb or small fan will be connected to the mud via an electrode. It was found that clay soil produced more energy than sandy soil. Also, an increase in water volume would dilute the mixture and this would slow down the transfer of energy in the mud. The results of this work can be useful for the environment and the decreasing energy sources.

Presented by:

Mahmoud Elsharafie, Kelton Vidal and Chiedza Tokonyai
Midwestern State University

General Interest
Room 104
(2019014) LEARNING IN TEXAS DELAWARE ROD PUMPING EXPERIENCE
More Information

Oxy Resources established the Texas Delaware Team in April 2013 when ~200 wells were purchased in the area of Pecos, Texas.  These primarily vertical wells produce from various commingled Delaware intervals located at 8,000’ to 12,000’ deep. The nature and deviation of these wells have made rod pumping them challenging and failure frequencies have been as high as 1.5 failures/year. Many lessons have been learned in driving the failure frequencies down to the current level of 1.0 failures/year. This paper will share some of the lessoned learned using various equipment types including fiberglass COROD, Poly-keytone Lined Tubing,  Poly-keytone Rod Glides, and Variable Slippage Pumps. 

Presented by:

Steve Gault and Tyler Anderson
OXY USA, Inc.

Artificial Lift
Room 106
(2019033) ALII (ARTIFICIAL LIFT INTAKE ISOLATION) TOOL, A NEW TECHNOLOGY FOR ISOLATING THE PRODUCTION TUBING ON PUMPING WELLS FOR SAFE AND EFFICIENT ROD AND PUMP CHANGES
More Information

The Artificial Lift Intake Isolation (ALII) tool is a new technology for rod pumping wells that when activated isolates the production tubing. The tool provides positive well control prior to breaking wellhead containment providing significant cost savings, safety and environmental protection. The tool is a simple two-part system, the first being the valve portion which is run just below the client’s pump-seating nipple in the production tubing string. The second is the actuator, which runs on the bottom of the insert rod pump. Tool activation is accomplished by simply running a rod pump with the actuator attached. When the pump is seated, the valve is opened for production; and when unseated the valve closes, isolating the tubing. The tool can be cycled multiple times. No additional equipment is required for tool operation and 100% positive shut off is provided which eliminates the need for kill fluids and eliminates the chance of formation gases or other fluids being released at the surface. There is no need for control lines to open and close the tool and there is the capability for utilizing the pump jack to cycle the tool open and closed. The tool also provides the capability for pressure testing the tubing when in the closed position. A number of benefits accrue through application of the tool to pumping wells and includes cost savings from reduced rig time to surface and re-run rod pumps, reduced trucking costs, reduced storage costs for kill fluids and minimizes the number of non-pumping days. Increased safety is realized as the tool provides positive well control prior to a well workover eliminating the chance of formation gases or other fluids being released at the surface. Environmental advantages include reducing the environmental footprint by decreasing water usage saving the local water supply. 

Presented by:

Kent Perry, Gas Technology Institute
Graeme Hines, Donald Slipchuk and Pete Krawiec, Revelation Management, LTD.

Artificial Lift
Room 107
(2019027) USE OF FACTORS THAT INFLUENCE ESP RUN LIFE
More Information

The ESP system is a mechanical/electrical/hydrodynamic system. It is costly when it fails as the tubing has to be pulled and much or all of the equipment is replaced. 
This paper points out tips in the below various areas that if considered are likely to increase the average run life of ESP Systems

-Failure definitions from data
-Design
-Installation
-SCADA-Monitoring
-Tips for running in Harsh Conditions
-Pulling
-Teardown Analysis
-RCFA and follow up
The information summarized includes industry findings and experience from the author’s backgrounds

Presented by:

James F Lea, PLTech, LLC. 
David Divine, Valiant ALS

Artificial Lift
Room 108
(2019037) REDUCING ROD PUMPS STICK IN THE TUBING IN THE HIGHWAY 80 FIELD
More Information

When an insert rod pump gets stuck in tubing there will be a significant increase in well-servicing events. These events cost the consumer money and also places the worker's safety at risk. 


The Highway 80 area reviewed the number of stuck rod pumps in tubing conditions that had occurred from 2010 to mid-2017.  In total, there were 825 pumps that were unable to be pulled with rods, which resulted in tubing being pulled to retrieve the pump. To try and resolve this issue Pioneer used a rubber fin element below the discharge of their insert rod pumps. By doing so they saw a reduction in stuck pumps with the rubber element. Even though this method decreased the number of stuck pumps, about 10% of their pumps continued to get lodged in the tubing. 


In the third quarter of 2017, Harbison-Fischer implemented a design change to these wells. The Harbison-Fischer Brush Sand Shields were installed to all insert pumps going forward.


This paper will discuss the early results of approximately 18 months since the first Brush Sand Shields were installed. We will compare the pumps pulled that were stuck in tubing with and without the design change since the implementation. Our goal is to continue to review the trend to see if positive results are achieved. We will track the data and present it again in 2020. We have calculated that the additional cost of pulling tubing is more than 50% more than if the pump can be retrieved with the rods.
 

Presented by:

Rodney Sands, Apergy - Harbison-Fischer
Rowland Ramos, Pioneer Natural Resources
Matt Horton, TWS Pump

Artificial Lift
Room 111
(2019021) REDUCING PIP BELOW 600 PSI BREAKING AND SEPARATING THE GAS SLUGS IN ESP: CASE STUDIES IN THE PERMIAN BASIN
More Information

High gas-liquid formation ratios appear as the fluid level decreases and as a result significant decreases in pumping efficiency are seen in the ESPs. This problem force frequent shutdowns in the pump because the gas is incapable of adequately cooling the motor and this forces the companies to maintain high fluid levels to avoid the formation of free gas at the pump intake, which increases the PIP and limits the production of fluid. A new and innovative downhole gas separator has been introduced in recent applications to treat gas slug’s problems. For these applications, a shrouded ESP with a double stage of gas separation connected to the bottom of the shroud as an intake was designed to break and separate gas slugs and avoid gas entrance into ESPs by forcing free gas to go around the shroud and produce through the casing. The gas separator uses an innovative design to break the gas slugs in the annular section between the casing and the tool, additional with the internal dual flow system the separation efficiency increases while it’s created a chamber lift filled with free gas liquid.  


With this new system, the fluid is now forced to pass through an additional gas separator which helps to separate gas and keeps lower PIP than usually promoting the fluid production in the wells.
 

Presented by:

Gustavo Gonzalez , Shivani Vyas, Odessa Separator Inc.
Carlos Loaiza, Chevron
Roger Maxim, Summit ESP

Artificial Lift

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

Room 101
(2019025) TAILPIPE SYSTEMS REQUIRE SMALL INTERNAL DIAMETERS
More Information

Horizontal wells can be difficult to produce with artificial lift systems. To address the problems of lifting these wells, tailpipe downhole separation systems have become more commonplace and have proven themselves to be effective at mitigating slug flow and improving artificial lift performance. Production increases of 30% to over 100% are frequently seen and pump run life can improve by 3-5 times in the right applications. However, designing a proper system to improve production and lift performance today and last for all, or a substantial portion of, the remaining producing life can be challenging and counter-intuitive. A key factor in the performance of these type of downhole separation systems is the internal diameter of the tailpipe. A review of 350 tailpipe systems installed in various basins reveals the importance of sizing the optimal internal diameter that balances draw down, slug flow mitigation and longevity as a well declines.

Presented by:

Dave Kimery, Jeff Saponka, Rob Hari and Kyla Gau
HEAL Systems

Artificial Lift
Room 103
(2019044) DATA SHARING - PROS, CONS, AND HOW TO LEVERAGE
More Information

Success in the oil and gas industry comes with effectively juggling four key elements: money (made or lost), risk, technical capability, and competition. Information is key to managing this process. Data sharing is the controlled process of providing information to and obtaining information from your competitors in such a manner to ensure your success (and theirs, as well). When well executed, data sharing can help one optimally find and develop highly profitable properties with minimal risk for failure. Unfortunately, poorly executed, the data sharing process can tilt the pursuit in the other direction, as well. This paper was prepared to provide the reader with an understanding of the data sharing process and how to effectively leverage information to succeed in such a competitive and technically challenging environment. There are many data sources available, with varying degrees of cost and value. A great deal of data is available for free from public sources, in a variety of formats. There is also an entire industry made up of companies that, for a fee, provide consistent methods to retrieve public data. They also provide value-added services to validate, scrub, and, sometimes, interpret the data. There are also services to find relevant information or, if necessary, to generate data. Each of these methods incurs some cost, whether it be directly financial, in terms of effort, or risk (due to reliability concerns). A great advantage of these methods is that there is no need to release valuable data to one’s competitors. The disadvantage is that a great deal of valuable information is not available via these avenues. This is where data sharing comes in, from consortia to directly sharing with potential competitors. Data sharing can be extremely valuable, not only in obtaining data but also in developing relationships that build information conduits and can lead to profitable operations that can only be pursued with a partner. While there is considerable value to this approach, there are challenges and hazards that need to be navigated. This paper describes the various methods of retrieving, purchasing, and sharing data and how to utilize data sharing as a mechanism to effectively compete in a challenging environment.

Presented by:

Jim Browning, Texas Tech University

General Interest
Room 104
(2019028) BEAM VSD ECONOMICS
More Information

Variable Frequency Drives (VFD) are a well-known method of pumping beam wells. By running the well continuously and adjusting pumping speed based on pump fillage, they provide unique benefits to reduce failures in difficult environments as compared to operating in pump-off control (POC); these environments might include solids, buckling tendencies at pump-off, and CO2 WAG environments. Although the industry recognizes the VFD benefits, many candidates remain on POC due to the capital investment required for a VFD purchase. This paper discusses two assets within Oxy Permian EOR and analyzes the economics of VFDs in order to assess if expanded usage is justified.

Presented by:

Daniel Lee, Steve Gault and Mike McNeely
OXY USA Inc.

Artificial Lift
Room 106
(2019005) GROUNDING FOR ESP LIGHTNING PROTECTION
More Information

How and where ground wires are connected determines the runtime and successful withstanding of switching and lightning surges. This is extremely evident with lightning protection of electric submersible pumps (ESP).  Electric surge suppressors on the same ground wire can and will interact bidirectionally in a lightning storm. Instances of ESP failures due to improperly installed surge suppression are not uncommon.  Understandably the value of surge suppression has been questioned.  This paper proposes separate ground wires for each surge device with all wires bonded together at the wellhead.  Justification for this is derived from multiple engineering reports on wellsite electrical installations, electrical theory and reported extended ESP run-life.

Presented by:

Tom Brinner, Subsaver, LLC
Don Parrott, G&W Consulting

Artificial Lift
Room 107
(2019024) DOG LEG SEVERITY (DLS) AND SIDE LOAD (SL) RECOMMENDATIONS
More Information

Dog Leg Severity (DLS) had been used for many decades as recommendations to try to drill oil and gas wells and provide "trouble free" operating conditions. Many of these recommendations were historically based on vertical, shallow (<5000 ft.) deep wells. But as wells continued to be drilled deeper, the recommendations were still applied. With the current drilling and operating practices of deviated and/or horizontal wells, these recommendations may no longer be applicable. Additionally, the deviation measurement interval (degrees/100 ft.) also may no longer be accurate when trying to match downhole problems using existing rod string design software. Furthermore, as wells have become deeper and many now also exclusively are drilled as deviated/ horizontal, side loading (SL) may be a more appropriate condition to be used to determine problems. This paper will review the historic DLS recommendations, provide insight on deviation measurement interval, discuss the importance of SL, and provide new recommendations for drilling wells that should provide better, longer term, less problematic operating wells.

Presented by:

Norm Hein, Oil & Gas Optimization Specialist, Ltd.
Lynn Rowlan, Echometer Company

Artificial Lift
Room 108
(2019038 CASING GAS SEPARATOR INITIAL INSTALLATION LEARNINGS AND DESIGN PROGRESSIONS
More Information

A new technology was released last year with the goal of being safe, easy to run and attaining previously unachievable gas separation when compared to any other method available today. The new technology is a gas separator built into the casing (CGS) and is run on the actual casing string right after the well has been drilled. CGS is run permanently into place on the casing with no alteration to the drilling program whatsoever. The CGS is commonly placed at kickoff point or in a tangent further downhole and well work occurs with absolutely no alteration to normal completion processes. The CGS can be run in multiple positions in the wellbore and two were run in the Rockies with different set points. One was at KOP and the other in a tangent. This paper will discuss the prejob planning with the Drilling Department, Completions Group and Production Team. The paper will go into the actual execution of each installation and the outcomes of the installs. The lessons learned led to multiple design progressions and development of ancillary tools to be run in conjunction with the CGS.

Presented by:

Brian Ellithorp and DJ Snyder
BlackJack Production Tools

Artificial Lift
Room 110
(2019022) MICRO-ENCAPSULATED TECHNOLOGY: NEW CHEMICAL TREATMENT FOR DOWNHOLE
More Information

The common surface chemical applications cannot reach or have low efficiency due to high fluid levels. This paper Introduces a new chemical technology for all types of artificial lift systems that guarantees an efficient downhole treatment at the entry point and summarizes the applications of this revolutionary method established to deliver chemical combinations by microencapsulating the compounds and packaging the completed formulation in a chemical screen that is placed at the bottom of the tubing (BHA) below any type of artificial lift systems. The new downhole Chemical treatment technology were designed and successfully applied in 3 wells in the Permian Basin to control scale and corrosion. The installation of the chemical tool is easily made up below the pump intake and not additional equipment is needed in the pump or in the surface facilities.

Presented by:

Gustavo Gonzalez, Renzo Arias, Luis Guanacas 
Odessa Separator Inc.

Artificial Lift
Room 111
(2019035) REDUCING ARTIFICIAL LIFT FAILURE RATE THROUGH OPTIMIZED TUBING INSPECTION
More Information

There are many potential failures in production wells which result from corrosive downhole environments, mechanical aspects of artificial lift or a combination thereof. Tubing failures constitute a costly failure mechanism in production wells. Tubing inspections can provide valuable insight on the condition of tubing as well as the distinction between causes of tubing degradation. This information is utilized to replace worn and pitted tubing joints, failure root cause analysis and implement solutions to mitigate future failures. Due to the high cost of a tubing failure, a high-quality tubing inspection is critical to identify potential failure mechanisms in a used tubing string. This paper serves to discuss the engineering and economic benefits of a tubing scanning program. The results of an in-plant inspection compared to an EMI wellhead inspection on two Anadarko wells in the Permian Basin exemplifies said benefits. This paper provides an in depth analysis of tubing inspection technology, the pros and cons of both wellhead and in-plant inspections and data utilization to reduce downhole failures.

Presented by:

Taylor Reeves, Anadarko Petroleum
Alexander Restreop, NOV Tuboscope

Artificial Lift

Thursday, April 18th

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

Room 101
(2019051) MAXIMIZE YOUR WELLBORE PRODUCTIVITY AND EUR USING THE EXCITE PIN-POINT REFRAC SYSTEM
More Information

Comitt Well Solutions’ Excite system is an innovative down hole tool specially designed for pin-point refracturing and re-stimulation applications. The system is fully hydraulic and can accommodate any space-out between its isolation packers. The patented technology treats each cluster in the wellbore in a single trip and allows treatment of both existing and newly added stages. Since the first successful field trial in 2017, the Excite system has been used in acid stimulation, proppant refrac, revitalization of SWD wells, leak detection, repairing of frac hit damage and many other applications. With average production uplift of 2-10 times post treatment and payout as low as 30 days, clients are seeing a great return on their investment. 

Presented by:

Brad Holmes and Shanshan McNeill
Comitt Well Solutions

Well Completion and Simulation
Room 102
(2019032) DEVELOPMENT OF A ROD GUIDE MODEL WHICH GENERATES A MINIMUM LEVEL OF TURBULENCE, PERFORMING CFD ANALYSIS AND HYDRODYNAMIC COMPARISONS BETWEEN DIFFERENT GUIDE DESIGNS
More Information

A hydrodynamic analysis for different rod guide designs simulating downhole fluid conditions was made using computational fluid dynamics (CFD) analysis, which is widely used for solving the partial differential equations of fluid motion by discrete approximation.  A particular turbulence kinetic energy graphic for each guide sample was created and compared to each other. The results shows a significant difference between the samples and the new rod guide design with conclusive proof of a better hydrodynamic performance. 

Presented by:

Ricardo Padron, Tenaris

Artificial Lift
Room 103
(2019050) REPLACING BRIDGE PLUGS CAN LEAD TO COST SAVINGS AND INCREASED PRODUCTION
More Information

Replacing bridge plugs with Perf PODs, to plug/divert individual perforations, allows Operators to divert the stimulation mid-stage and reduce the total number of bridge plugs within a wellbore while maintaining the advantages of closer stage spacing and adding additional clusters.  The risk of a pre-set plug can be drastically reduced, along with pump down time, completion cost and resources associated for the corresponding wireline runs and subsequent millout work.  Applying Perf POD diversion technology between bridge plugs allows the Operator to achieve maximum cluster efficiency, while stimulating the entire stage, without leaving orphan clusters behind.  This ensures a more consistent stimulation volume pumped into each perforation cluster, ultimately providing a more balanced treatment and reducing the probability of a “runway frac”, which could potentially damage offset wells.   


Based on current stimulation design - are you effectively stimulating every cluster?
 

Presented by:

Jenna Robertson, Thru Tubing Solutions

Prod. Handling
Room 104
(2019014) LEARNING IN TEXAS DELAWARE ROD PUMPING EXPERIENCE
More Information

Oxy Resources established the Texas Delaware Team in April 2013 when ~200 wells were purchased in the area of Pecos, Texas.  These primarily vertical wells produce from various commingled Delaware intervals located at 8,000’ to 12,000’ deep. The nature and deviation of these wells have made rod pumping them challenging and failure frequencies have been as high as 1.5 failures/year. Many lessons have been learned in driving the failure frequencies down to the current level of 1.0 failures/year. This paper will share some of the lessoned learned using various equipment types including fiberglass COROD, Poly-keytone Lined Tubing,  Poly-keytone Rod Glides, and Variable Slippage Pumps. 

Presented by:

Steve Gault and Tyler Anderson
OXY USA, Inc.

Artificial Lift
Room 106
(2019018) ITS ALL ABOUT THE END FITTING 3: PRESSURE DROP, EXTRA CORROSION CAPABILITY, COMPRESSION HANDLING
More Information

As fluctuations in oil price continue, the industry has changed and is demanding improvements from each method of artificial lift. Required flow rates are increasing due to the longer laterals of new horizontal wells being added to inventory. Rod Lift is not immune and is being asked to enter the artificial lift cycle earlier and support the pumping of wellbores with added complexities due to geometries and/or production demands. The fiber reinforced plastic (fiberglass, FSR) rod continues to meet the ever-increasing demand and complexities. The two previous editions of ‘IT’S ALL ABOUT THE END FITTING’ focused on the design of the new generation of fiberglass rod, the added strength the industry has requested, the benefits regarding the handling of compression and methods to mitigate uncertainties of the wellbore dynamics. This edition will focus on benefits of the latest generation of the end fitting. It will explain how a new configuration of the wedge profile provides reduced pressure drop at each connection and/or adds corrosion resilience. The new wedge profile also increases the ability of the end fitting to handle compression. Data will be provided in support of increased production. The fiberglass rods have been delivering benefits for the last 30+ years to the industry and continue to maintain pace with growing demands of artificial lift through innovation and development of new generation FSRs. With an ongoing progress of FSR technology the glass rods are being adopted earlier in the well’s life cycle requiring us to make the product RUN LONGER & PRODUCE 

Presented by:

Ryan Gernentz, Karol Hricisak and Alex Booth
Endurance Lift Solutions

Artificial Lift
Room 107
(2019015) SHOOTING FLUID LEVELS IN CO2 APPLICATIONS
More Information

In 2014 Oxy EOR had lost confidence in the accuracy of Fluid Levels in CO2 wells and was not shooting them. Echometer and Oxy collaborated to identify the root cause of the fluid level inaccuracy and resolve the issue through improved procedures and educating personnel. Today trusted fluid level information adds value by improved operational decision making. 

Presented by:

Erilck Cameron , Joe Johnson, Sebastian Millan Ryan Owen, Calvin Stewart and Steve Gault,  OXY USA, Inc.
Lynn Rowlan, Echometer Company

Artificial Lift
Room 108
(2019006) VALIDATION OF FRICTION COEFFICIENT AND WEAR CONCEPTS IN SUCKER ROD LIFT SYSTEMS
More Information

In some of today’s unconventional wells, sucker rod pumping systems are facing challenges related to excessive wear, affecting production and increasing operational costs. One of the reoccurring damages in a sucker rod pumped well occurs near the kick-off point in a deviated well between the coupling and the tubing or between the sucker rod and the tubing; the metal-to-metal contact causes hole-in-tubing failures and operators have been seeking solutions to mitigate or minimize excessive tubing wear in highly deviated wells. Wear caused by both metal contact and abrasive particles, as well as corrosive attack from the wellbore’s fluid also affects the metal integrity of the tubing, coupling and sucker rod. It is beneficial to develop fundamental understanding on wear and friction concepts in rod lift applications, to optimize rod lift product designs and improve Mean Time Between Failures (MTBF) in deviated wells.

In this paper, the concepts of friction and wear will be explained from applied rod lift engineering perspective. Field tested solutions to reduce tubing wear will be presented with lab and field data.

Presented by:

Wanru Shang, Pablo E. Barajas and Reza Eghtesad
Apergy Rod Lift

Artificial Lift
Room 109
(2019021) REDUCING PIP BELOW 600 PSI BREAKING AND SEPARATING THE GAS SLUGS IN ESP: CASE STUDIES IN THE PERMIAN BASIN
More Information

High gas-liquid formation ratios appear as the fluid level decreases and as a result significant decreases in pumping efficiency are seen in the ESPs. This problem force frequent shutdowns in the pump because the gas is incapable of adequately cooling the motor and this forces the companies to maintain high fluid levels to avoid the formation of free gas at the pump intake, which increases the PIP and limits the production of fluid. A new and innovative downhole gas separator has been introduced in recent applications to treat gas slug’s problems. For these applications, a shrouded ESP with a double stage of gas separation connected to the bottom of the shroud as an intake was designed to break and separate gas slugs and avoid gas entrance into ESPs by forcing free gas to go around the shroud and produce through the casing. The gas separator uses an innovative design to break the gas slugs in the annular section between the casing and the tool, additional with the internal dual flow system the separation efficiency increases while it’s created a chamber lift filled with free gas liquid.  


With this new system, the fluid is now forced to pass through an additional gas separator which helps to separate gas and keeps lower PIP than usually promoting the fluid production in the wells.
 

Presented by:

Gustavo Gonzalez , Shivani Vyas, Odessa Separator Inc.
Carlos Loaiza, Chevron
Roger Maxim, Summit ESP

Artificial Lift
Room 110
(2019026) CASE STUDY - USE OF CAPILLARY STRING ASSISTED ARTIFICIAL LIFT AT THE ADAIR SAN ANDRES UNIT
More Information

The Apache-operated Adair San Andres Unit (ASAU) currently employs fifteen capillary string (cap string) equipped producing wells, representing 16% of the active producer count. Apache started converting producing wells to cap strings in 2016.  This idea was introduced to Apache at the 2012 CO2 Conference in Midland and later reinforced during a field tour of Whiting’s North Ward Estes CO2 flood in 2015.  The chief benefit using a cap string is production stability.  A review of these installations 
is categorized by a reduction in production variance, meaning an increase in stability - be it oil and gas production, or water-oil and gas-liquid ratio (GLR).  This equates to less rig intervention, more uptime.  Of note: 1) a cap string will successfully operate below the minimum GLR of 400 SCF/BBL/1000’ required by plunger lift, 2) conversion to cap string assisted lift is not affected by the wellbore geometry, and 3) ASAU installations are packer-less.

Presented by:

Rebecca Larkin and Joe Lopez
Apache Corp.

Artificial Lift
Room 111
(2019035) REDUCING ARTIFICIAL LIFT FAILURE RATE THROUGH OPTIMIZED TUBING INSPECTION
More Information

There are many potential failures in production wells which result from corrosive downhole environments, mechanical aspects of artificial lift or a combination thereof. Tubing failures constitute a costly failure mechanism in production wells. Tubing inspections can provide valuable insight on the condition of tubing as well as the distinction between causes of tubing degradation. This information is utilized to replace worn and pitted tubing joints, failure root cause analysis and implement solutions to mitigate future failures. Due to the high cost of a tubing failure, a high-quality tubing inspection is critical to identify potential failure mechanisms in a used tubing string. This paper serves to discuss the engineering and economic benefits of a tubing scanning program. The results of an in-plant inspection compared to an EMI wellhead inspection on two Anadarko wells in the Permian Basin exemplifies said benefits. This paper provides an in depth analysis of tubing inspection technology, the pros and cons of both wellhead and in-plant inspections and data utilization to reduce downhole failures.

Presented by:

Taylor Reeves, Anadarko Petroleum
Alexander Restreop, NOV Tuboscope

Artificial Lift

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

Room 101
(2019052) MAXIMIZE YOUR WELLBORE PRODUCTIVITY AND EUR USING THE EXCITE PIN-POINT REFRAC SYSTEM
More Information

Comitt Well Solutions’ Excite system is an innovative down hole tool specially designed for pin-point refracturing and re-stimulation applications. The system is fully hydraulic and can accommodate any space-out between its isolation packers. The patented technology treats each cluster in the wellbore in a single trip and allows treatment of both existing and newly added stages. Since the first successful field trial in 2017, the Excite system has been used in acid stimulation, proppant refrac, revitalization of SWD wells, leak detection, repairing of frac hit damage and many other applications. With average production uplift of 2-10 times post treatment and payout as low as 30 days, clients are seeing a great return on their investment. 

Presented by:

Brad Holmes and Shanshan McNeill
Comitt Well Solutions

Artificial Lift
Room 102
(2019046) DYNAMIC FILTRATION TEST EXPERIMENTS DESIGN
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The purpose of this project is to conduct a Dynamic Filtration Test to Investigate the Effect of Preformed Particle Gels (PPGs) on Un-swept, Low-Permeable Zones/Areas. A filtration test is a simple means of evaluating formation damage. This work use schematically dynamic filtration test experiment design apparatus to carry out the various filtration test experiments. It use different core samples, various brine concentration, and various gel types.  The permeability   of each sandstone core samples is calculated before and after the filtration test. Experiments are still being observed.  The objective of this study is to find methods that minimized the damage caused by PPGs on un-swept, low-permeable zones/areas, thus improving PPG treatment efficiency. This approach will identify the best properties of the PPGs, which can neither penetrate conventional solid rocks nor form cakes on the rocks’ surface. 
 

Presented by:

Mahmoud Elsharafi, Jenom Pyeng , Tapiwa Gasseler, and Jedeshkeran Chandraseqaran
Midwestern State University

General Interest
Room 103
(2019049) DATA-DRIVEN PROGNOSTIC METHOD FOR EQUIPMENT IN OIL AND GAS INDUSTRY
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Catastrophic accidents in offshore drilling operations have greatly endangered human lives, environment and capital assets. Although risks in offshore oil and gas operations cannot be completely eliminated, a substantial amount of risks can be minimized through preventive and mitigative measures. A key aspect of the offshore drilling risk is the reliability of drilling systems. According to the World Offshore Accident Dataset and many other investigations, the overwhelming majority of disastrous accidents in offshore drilling operations were caused by equipment failures and human errors. The capabilities to predict the lifetime and provide early and effective warnings in real time are crucial to ensure reliable and safe offshore operations. The objective of this research is to mitigate offshore drilling risks by developing a scientific framework for data-driven failure prognosis for complex drilling systems operating in heterogeneous and extremely harsh environments. A novel data-driven reliability model in conjunction with a systems and economic impact analysis is developed integrating multi-source (e.g., operations and maintenance records, in-situ monitoring data) and multi-modal (e.g., lifetime data, degradation profiles) data. Numerical cases studies will be presented to demonstrate the proposed method. 
 

Presented by:

Yisha Xiang, Mario Beruvides and Lloyd Heinze
Texas Tech University

General Interest
Room 104
(2019017) DOWNHOLE EQUIPMENT REPLACEMENT GUIDELINES
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In 2017 and 2018 Oxy EOR conducted a series of RCFA schools. As part of these schools, information was gathered on the range of equipment replacement for failure types. In 2018, a cross functional team of experienced stakeholders vetted this information and compiled a list of equipment replacement guidelines. This paper will share these guidelines. 

Presented by:

Steve Reed, Calvin Stewart, Steve Gault, Saul Tovar, Joel Gallegos and Rynn Peeler
OXY USA Inc.

Artificial Lift
Room 106
(2019005) GROUNDING FOR ESP LIGHTNING PROTECTION
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How and where ground wires are connected determines the runtime and successful withstanding of switching and lightning surges. This is extremely evident with lightning protection of electric submersible pumps (ESP).  Electric surge suppressors on the same ground wire can and will interact bidirectionally in a lightning storm. Instances of ESP failures due to improperly installed surge suppression are not uncommon.  Understandably the value of surge suppression has been questioned.  This paper proposes separate ground wires for each surge device with all wires bonded together at the wellhead.  Justification for this is derived from multiple engineering reports on wellsite electrical installations, electrical theory and reported extended ESP run-life.

Presented by:

Tom Brinner, Subsaver, LLC
Don Parrott, G&W Consulting

Artificial Lift
Room 107
(2019027) USE OF FACTORS THAT INFLUENCE ESP RUN LIFE
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The ESP system is a mechanical/electrical/hydrodynamic system. It is costly when it fails as the tubing has to be pulled and much or all of the equipment is replaced. 
This paper points out tips in the below various areas that if considered are likely to increase the average run life of ESP Systems

-Failure definitions from data
-Design
-Installation
-SCADA-Monitoring
-Tips for running in Harsh Conditions
-Pulling
-Teardown Analysis
-RCFA and follow up
The information summarized includes industry findings and experience from the author’s backgrounds

Presented by:

James F Lea, PLTech, LLC. 
David Divine, Valiant ALS

Artificial Lift
Room 108
(2019003) EVALUATION OF C GRADE RODS AND T COUPLING USAGE IN SAN ANDRES CONVENTIONAL
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In 2016, a recommendation was made in EOR to begin utilizing Grade “C” when replacing rods in San Andres wells or wells less than 5,000’ deep. The advantage of the Grade “C” rods believed to be better corrosion resistance, tubing leak reduction, and lower material cost. It was also recommended that “T” coupling be considered as an alternative to Spray Metal (“SM”) couplings as they are softer and should fail preferentially to the tubing. As with any technology that is new to the field in question there is concern about wide spread use until sufficient data is gathered on a smaller subset of wells to prove up the concept. As failure frequency is a key metric when evaluating artificial lift performance, and it can take several years to develop sufficient data, an analysis method needed to be utilized to track the equipment performance over a shorter duration so that use can be expanded as early as possible. This was accomplished by developing statistical data for sucker rod and coupling installations and failures over a specific time period comparing the failure rate of the “C” rods and “T” couplings versus the “KD” rods and “SM” couplings that are typically run. The analysis showed that the “C” grade rods and “SM” couplings were not showing an increased failure rate and therefore provided support to start expanding their use in EOR, which should result in significant cost savings. To further understand the corrosion differences between C-Rods and KD-Rods corrosion coupons were constructed from sections of actual rods and placed in several wells of varying characteristics. This paper will also present the findings from this corrosion test, which is currently nearing completion. 

Presented by:

Garrett Best, Steven Reedy, Calvin Stewart and Steve Gault
OXY USA, Inc.

Artificial Lift
Room 109
(2019007) SAND FLUSH PLUNGER PERFORMANCE IN THE HWY 80 FIELD UPDATE
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The performance of Harbison-Fischer’s patented Sand Flush Plunger (SFP) was assessed relative to the average runtime for standard API plungers in the HWY 80 field, operated by Pioneer Natural Resources (PNR). The field case study captured information from pump-tracker for 5,283 wells and 32,804 workover records dating back to 1989. As of the record date 1,934 different wells had used a SFP 3,473 times. The analysis, however, focused in 194 wells for each of whom the data showed at least 1 failure originated by the pump for each of the two plunger types. The average runtime for the SFP and the API plungers were found to be 1,178 days and 579 days, respectively.

The present study constitutes an update on the continuous monitoring of the performance of the SFP that has been carried out in HWY 80 field since 2015. The average runtime for the SFP was reduced in 119 days whereas the average runtime for the API pumps increased by 36 days. The number of wells considered for calculating the average runtimes has gone up by 37 wells from 157 reported in 2015. Similarly, the number of qualifying pump changes has increase by 102 from 486 reported back in 2015. The data processing has been carried out using Tableau, and slightly different criterions for cleaning the records have been implemented compared to the paper presented in 2015 at this same conference.

Presented by:

Felipe Correa, Apergy - Harbison-Fischer

Artificial Lift
Room 110
(2019008) FIELD-DRIVEN INITIATIVE TO IMPROVE ARTIFICIAL LIFT EFFICIENCY AND RELIABILITY WITH AN ENGINEERED SUCKER ROD PUMP BALL VALVE INSERT
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To increase recovery rates – the greatest challenge facing the industry – operators must not only look to step-change technologies, but improvements to existing technology. Even incremental increases in recovery rates can impact economics when multiplied across numerous wells. For example, approximately two-thirds of onshore wells use beam operated pump jacks with reciprocating rod pumps. Our objective was to improve the efficiency and reliability of sucker pumps by engineering a new ball valve insert.  Prototype testing demonstrated that the lowest pressure drop was provided by an insert design with the tangent angle equal to Pi (3.14, π), as it forced the fluid into a vortex spin. Based on a number of flow rates (including two phase flow) the TangentFlow Insert decreased pressure drop by 40% on average resulting in 58% more flow than the bar-bottom inserts. In addition, compared to the bar-bottom inserts, which produced significant ball chatter, the TangentFlow Insert had a consistently low decibel reading with increasing flow rates, as the ball remained stationary. This results in reduced gas breakout, which in turn further reduces pressure drop, fluid pound and pump damage.  One-year field results from 50 wells in the Red River reservoir of Montana and North Dakota demonstrate that the TangentFlow Insert reduced pressure drop across both the standing and traveling valves to increase average surface flow by 8%. Considering the average water to oil ratio in the area, this provides an additional 3.1 bbl/day/well. This increase applied over 50 wells translates to approximately 54,603 bbl/year, or $3.33MM in revenue at current oil prices.  The design of the TangentFlow Insert improves the efficiency and reliability of sucker rod pumps by minimizing the effects of pressure drop, gas breakout, solids accumulation (wax), casing wear and ball wear, which together improve pump efficiency and production flow. Because the design enables the ball to remain stationary, smaller and lighter balls can be used, allowing for higher flowback solids and reduced cage wear, respectively. The TangentFlow Insert is manufactured to replace conventional bar-bottom inserts without needing to change out the entire pump assembly, making them applicable to 90% of pumps presently used in the industry.

Presented by:

Corbin Coyes, TangentFlow Inc.

Artificial Lift
Room 111
(2019001) ANNULAR GAS LIFT IN THE DELAWARE BASIN
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Evolution of annular gas lift candidates and early results of application in the Delaware Basin. 

Presented by:

Kale Baker, Anadarko
 

Artificial Lift

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

Room 101
(2019031) UNDERSTANDING CAVITATION ON HYDRAULIC JET PUMPS, A SOLID AND EASY TO IMPLEMENT GUIDELINE TO AVOID AND MITIGATE CAVITATION DAMAGE
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The cavitation phenomenon has been extensively studied for many years, however, guidelines on how to implement this existing knowledge to the actual operation of the jet pumping systems in the oilfield are not abundant and, as per the author can see it, not yet being presented in such way that the people that operate these systems in the oilfield could implement on a straight forward way. It has been proven that using a scientific and easy to follow methodology, it is possible to prevent jet pump operating problems related to cavitation, during the early, middle and late stage of the well production life. Preventative and Corrective methodologies are based on: Measured production rates, power fluid rate and pressure, gas to liquid ratio, jet pump seating depth and jet pump nozzle/throat combination.

This paper presents a straight forward discussion on the jet pump cavitation, its hydrodynamics, causes, identification, potential damage, consequences on the jet pump performance and methods to predict it and avoid it.

Presented by:

Osman A. Nunez-Pino, Liberty Lift Solutions LLC

Artificial Lift
Room 102
(2019040) MAXIMIZING PRODUCTION EFFICIENCY IN BEAM PUMP WELLS USING ROD GUIDE DESIGN OPTIMIZATION
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There are many challenges associated with sucker rod lift in deviated wellbores that can lead to high failure rates and lost production. Tubing failures are amongst the costliest workovers and are often a result of metal to metal contact between the rod coupling and the tubing. Evaluating tubing on-site using both gamma and electromagnetic inspection allows for proper design optimization before returning to production. The tubing scan can be aligned with deviation data, previous rod design, and failure history to adjust the string design to effectively extend mean time between failures and improve asset value. An effective rod guide strategy was developed to mitigate tubing wear using proper guide type, material, and placement. The implementation of this strategy has helped to maximize production efficiency across the asset. 

Presented by:

Brian Wagner, NOV Tuboscope

Artificial Lift
Room 103
(2019044) DATA SHARING - PROS, CONS, AND HOW TO LEVERAGE
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Success in the oil and gas industry comes with effectively juggling four key elements: money (made or lost), risk, technical capability, and competition. Information is key to managing this process. Data sharing is the controlled process of providing information to and obtaining information from your competitors in such a manner to ensure your success (and theirs, as well). When well executed, data sharing can help one optimally find and develop highly profitable properties with minimal risk for failure. Unfortunately, poorly executed, the data sharing process can tilt the pursuit in the other direction, as well. This paper was prepared to provide the reader with an understanding of the data sharing process and how to effectively leverage information to succeed in such a competitive and technically challenging environment. There are many data sources available, with varying degrees of cost and value. A great deal of data is available for free from public sources, in a variety of formats. There is also an entire industry made up of companies that, for a fee, provide consistent methods to retrieve public data. They also provide value-added services to validate, scrub, and, sometimes, interpret the data. There are also services to find relevant information or, if necessary, to generate data. Each of these methods incurs some cost, whether it be directly financial, in terms of effort, or risk (due to reliability concerns). A great advantage of these methods is that there is no need to release valuable data to one’s competitors. The disadvantage is that a great deal of valuable information is not available via these avenues. This is where data sharing comes in, from consortia to directly sharing with potential competitors. Data sharing can be extremely valuable, not only in obtaining data but also in developing relationships that build information conduits and can lead to profitable operations that can only be pursued with a partner. While there is considerable value to this approach, there are challenges and hazards that need to be navigated. This paper describes the various methods of retrieving, purchasing, and sharing data and how to utilize data sharing as a mechanism to effectively compete in a challenging environment.

Presented by:

Jim Browning, Texas Tech University

General Interest
Room 104
(2019013) THE ECONOMIC TRADEOFFS IN DEVIATING WELLS TO PRODUCE FROM DOWNHOLE LOCATIONS THAT EXACTLY COMPLETE INJECTION PATTERNS
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In today’s world it can be challenging to locate the downhole well location immediately below the surface location in secondary and tertiary projects. There are several factors that must be considered when picking the surface location that will maximize value including 1) increases cost of building a location and drilling, 2) increases cost of artificial lift and operations, and 3) production rate and reserve impact.  This paper will explore how these factors can be put in an Excel Spread Sheet to assist in picking the location that will maximize value. 

Presented by:

Steve Gault, Erileck Cameron, Joe Johsnon, Sebastian Millan, Ryan Owen and  Calvin Stewart
OXY USA, Inc.

Artificial Lift
Room 106
(2019033) ALII (ARTIFICIAL LIFT INTAKE ISOLATION) TOOL, A NEW TECHNOLOGY FOR ISOLATING THE PRODUCTION TUBING ON PUMPING WELLS FOR SAFE AND EFFICIENT ROD AND PUMP CHANGES
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The Artificial Lift Intake Isolation (ALII) tool is a new technology for rod pumping wells that when activated isolates the production tubing. The tool provides positive well control prior to breaking wellhead containment providing significant cost savings, safety and environmental protection. The tool is a simple two-part system, the first being the valve portion which is run just below the client’s pump-seating nipple in the production tubing string. The second is the actuator, which runs on the bottom of the insert rod pump. Tool activation is accomplished by simply running a rod pump with the actuator attached. When the pump is seated, the valve is opened for production; and when unseated the valve closes, isolating the tubing. The tool can be cycled multiple times. No additional equipment is required for tool operation and 100% positive shut off is provided which eliminates the need for kill fluids and eliminates the chance of formation gases or other fluids being released at the surface. There is no need for control lines to open and close the tool and there is the capability for utilizing the pump jack to cycle the tool open and closed. The tool also provides the capability for pressure testing the tubing when in the closed position. A number of benefits accrue through application of the tool to pumping wells and includes cost savings from reduced rig time to surface and re-run rod pumps, reduced trucking costs, reduced storage costs for kill fluids and minimizes the number of non-pumping days. Increased safety is realized as the tool provides positive well control prior to a well workover eliminating the chance of formation gases or other fluids being released at the surface. Environmental advantages include reducing the environmental footprint by decreasing water usage saving the local water supply. 

Presented by:

Kent Perry, Gas Technology Institute
Graeme Hines, Donald Slipchuk and Pete Krawiec, Revelation Management, LTD.

Artificial Lift
Room 107
(2019036) DETERMINING OPTIMIZED GAS INJECTION RATE FOR GAS LIFTED WELLS TO MAXIMIZE LIFT EFFICIENCY
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Problem being addressed: Determining optimized Gas Injection Rate for Gas Lifted wells to maximize lift efficiency. Challenges: While Gas Lift is the most natural artificial lift method, ever-changing surface and downhole conditions cause significant inefficiencies. The changing conditions require frequent adjustments to surface-injected gas rates to maintain the most efficient lifting gradient. If the proper adjustments are not made, these inefficiencies may hinder production and increase lease operating expenses. Solution: By using Apergy’s proprietary hunting algorithm, Bloodhound, optimal gas injections rates are determined by the magnitude in the bottom hole pressure drawdown, with use of a permeant down hole gauge. Through continuous and proportional rate adjustment, the Bloodhound algorithm learns from previous set point deltas and tests against the inferred optimal rate, as well as changing conditions. Results: In under-injection scenarios, Bloodhound can accelerate the recovery of oil by up to 10 percent, regardless of the well’s position on its natural decline. In over-injecting scenarios, wells can maintain oil production rates while using up to 50 percent lift gas. Both results can be successfully achieved with few engineering hours, manually calculating or modeling well performance curves to determine inferred optimal rate. 
 

Presented by:

Dustin Sandidge, Apergy

Artificial Lift
Room 108
(2019024) DOG LEG SEVERITY (DLS) AND SIDE LOAD (SL) RECOMMENDATIONS
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Dog Leg Severity (DLS) had been used for many decades as recommendations to try to drill oil and gas wells and provide "trouble free" operating conditions. Many of these recommendations were historically based on vertical, shallow (<5000 ft.) deep wells. But as wells continued to be drilled deeper, the recommendations were still applied. With the current drilling and operating practices of deviated and/or horizontal wells, these recommendations may no longer be applicable. Additionally, the deviation measurement interval (degrees/100 ft.) also may no longer be accurate when trying to match downhole problems using existing rod string design software. Furthermore, as wells have become deeper and many now also exclusively are drilled as deviated/ horizontal, side loading (SL) may be a more appropriate condition to be used to determine problems. This paper will review the historic DLS recommendations, provide insight on deviation measurement interval, discuss the importance of SL, and provide new recommendations for drilling wells that should provide better, longer term, less problematic operating wells.

Presented by:

Norm Hein, Oil & Gas Optimization Specialist, Ltd.
Lynn Rowlan, Echometer Company

Artificial Lift
Room 109
(2019018) ITS ALL ABOUT THE END FITTING 3: PRESSURE DROP, EXTRA CORROSION CAPABILITY, COMPRESSION HANDLING
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As fluctuations in oil price continue, the industry has changed and is demanding improvements from each method of artificial lift. Required flow rates are increasing due to the longer laterals of new horizontal wells being added to inventory. Rod Lift is not immune and is being asked to enter the artificial lift cycle earlier and support the pumping of wellbores with added complexities due to geometries and/or production demands. The fiber reinforced plastic (fiberglass, FSR) rod continues to meet the ever-increasing demand and complexities. The two previous editions of ‘IT’S ALL ABOUT THE END FITTING’ focused on the design of the new generation of fiberglass rod, the added strength the industry has requested, the benefits regarding the handling of compression and methods to mitigate uncertainties of the wellbore dynamics. This edition will focus on benefits of the latest generation of the end fitting. It will explain how a new configuration of the wedge profile provides reduced pressure drop at each connection and/or adds corrosion resilience. The new wedge profile also increases the ability of the end fitting to handle compression. Data will be provided in support of increased production. The fiberglass rods have been delivering benefits for the last 30+ years to the industry and continue to maintain pace with growing demands of artificial lift through innovation and development of new generation FSRs. With an ongoing progress of FSR technology the glass rods are being adopted earlier in the well’s life cycle requiring us to make the product RUN LONGER & PRODUCE 

Presented by:

Ryan Gernentz, Karol Hricisak and Alex Booth
Endurance Lift Solutions

Artificial Lift
Room 110
(2019020) INNOVATIVE PACKER TYPE GAS SEPARATOR:  OPERATING PRINCIPLES AND DESIGN CRITERIA
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Wells with high depletion rate present high free gas at pump intake conditions. In all cases, the production of fluid with a high gas-liquid ratio leads to an inefficient performance of the rod pump systems. The initial solution to this problem is the installation of poor boy gas separators which capacity of gas separation is reduced and do not provide a high-performance solution.  Packer type gas separators are the most efficient downhole separators in the market, however, they usually have some operational limitations. This paper summarizes a new design of the packer type gas separator which uses more methods of separation than the traditional design and can be designed based on the conditions of each well overcoming the typical limitations. The design criteria are reviewed, and some operational guidelines are listed to reach the best performance in each application for gas separation.

Presented by:

Gustavo Gonzalez, Shivani Vyas, Luis Guanacas Neil Johnson
Odessa Separator Inc.

Artificial Lift
Room 111
(2019030) HIGH RATE UNCONVENTIONAL GAS LIFT
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The purpose of this paper is to discuss the history of different gas lift design methods and the theory behind a new design method.  In January 2019, Production Lift Companies and Concho Resources ran a new gas lift design method in two unconventional wells in the Permian Basin.  This new method is designed to exploit the initial high bottom hole pressure in unconventional wells to produce higher rates that, before now, were only possible with an ESP.  This life of well design will also follow the well’s decline and efficiently produce the well at lower rates.  When completed correctly, the well can be switched to PAGL, Plunger Lift or GAPL without pulling the tubing.  

The traditional gas lift design method for unconventional wells is to run unloading valves until you reach a minimum spacing of 500’ (Fig. 1) and then continue the 500’ spacing to the packer.  The 500’ spacing was adopted by the industry in the late 80’s as “Best Practice” and has remained the standard today. 
 

Presented by:

Jay Miller, Production Lift Companies
Kenneth Estrada, Concho

Artificial Lift

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

Room 101
(2019039) ANALYSIS AND OPTIMIZATION OF SUCKER-ROD PUMP DESIGN
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Rod lift design methods remain overwhelmingly unchanged since the mid-20th century. Meanwhile, drilling and completion technology has undergone a dramatic transformation. The innovation gap between the two technologies and low-flow artificial lift has resulted in the need for improved design and workflow methods to more effectively operate an unconventional well throughout its lifecycle. New design and workflow processes have been developed that improve upon today’s common practices through the observation of unconventional well characteristics and root cause analysis of equipment failure. This new design and workflow process has resulted in improved performance for unconventional wells in the Permian Basin.

Presented by:

Levins Thompson, Zack Smith and Ricky Roderick
Don-Nan Pump and Supply

Artificial Lift
Room 103
(2019045) ENERGY FROM SALTWATER MUD
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There is a growing need for energy throughout the world and this increase in demand for energy has now also put a strain on the current sources of energy. In the process of oil/gas production, there are large amounts of water released into the atmosphere as well as into the ground or soil. This water contains chemicals such as Sulphur and Nitrogen oxides, Bitumen, Calcium, Base oil, and Sodium. It is commonly referred to as “wastewater” and is disposed of. The goal of this project is to investigate the possibility of acquiring energy from this wastewater. This is can be done by using various types of soils and water. Various mixtures were created using soils mixed with different percentages of clay and water with varying salinity. A small source of electricity was then applied to the saltwater mud to provide a voltage to the experiment. The chemicals in the mud are then expected to amplify the input voltage and create enough energy to power electrical devices. To prove this, a bulb or small fan will be connected to the mud via an electrode. It was found that clay soil produced more energy than sandy soil. Also, an increase in water volume would dilute the mixture and this would slow down the transfer of energy in the mud. The results of this work can be useful for the environment and the decreasing energy sources.

Presented by:

Mahmoud Elsharafie, Kelton Vidal and Chiedza Tokonyai
Midwestern State University

General Interest
Room 104
(2019028) BEAM VSD ECONOMICS
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Variable Frequency Drives (VFD) are a well-known method of pumping beam wells. By running the well continuously and adjusting pumping speed based on pump fillage, they provide unique benefits to reduce failures in difficult environments as compared to operating in pump-off control (POC); these environments might include solids, buckling tendencies at pump-off, and CO2 WAG environments. Although the industry recognizes the VFD benefits, many candidates remain on POC due to the capital investment required for a VFD purchase. This paper discusses two assets within Oxy Permian EOR and analyzes the economics of VFDs in order to assess if expanded usage is justified.

Presented by:

Daniel Lee, Steve Gault and Mike McNeely
OXY USA Inc.

Artificial Lift
Room 106
(2019041) A SUCCESSFUL BAKKEN FAILURE REDUCTION PROGRAM
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Oasis Petroleum has ~1000 rod pump wells in the Bakken producing from 8000’ - 10,000’. A focused effort has been made over the past few years to reduce the failure rate from ~1.0 failures/well/year to the current rate of .68 failures/well/year. This has been the result of a holistic approach which has encompassed improvements in rod design, surveillance, training, development of Standard Operating Procedures and Best Practices, trialing new technology and POC optimization. This paper will document some of the successes and failures during this journey.

Presented by:

Will Whitley, Matt Chapin, Lauren Coles and Karla Traweek 
Oasis Petroleum

Artificial Lift
Room 107
(2019004) ROD PUMP CLEARANCE GUIDANCE
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Slippage is required for lubricating the plunger/barrel within beam pumping systems. Increasing pump clearance increases the amount of slippage, which may lead to inefficient operations. Operators could run their field more efficiently through decreasing failure rate and increased electrical cost savings by calculating the optimum design using the Patterson Slippage equation for individual well conditions. This paper will discuss the economic tradeoffs with changing pump clearances and recommend theoretical optimum designs given well conditions. The paper will also include nomographs and a calculator to recommend optimum designs. 

Presented by:

Stephen Borcik  and Steve Gault, OXY USA, Inc.
Lynn Rowlan, Echometer Company

Artificial Lift
Room 108
(2019034) IRIS: A NEW ERA IN DOWNHOLE DATA TREATMENT
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When optimizing a reciprocating rod lift installation, key control parameters must be extracted from the downhole data. Traditionally, downhole data in the form of position and load data is derived from surface data using the wave equation. Downhole position and load data must be carefully analyzed to extract key control parameters for reciprocating rod lift optimization.
IRIS introduces a new and innovative approach for downhole data analysis.


Through a change in coordinate system, IRIS transforms downhole position and load data into polar coordinates. This change in coordinates creates three new data sets, which greatly simplify the extraction of the above mentioned key control parameters.
Additionally, IRIS can be used to manage both viscous and mechanical friction through an extra friction detection algorithm and a viscous damping estimator.


In this paper, the IRIS algorithms and results are presented.
 

Presented by:

Victoria Pons, Baker Hughes, A GE Company

Artificial Lift
Room 109
(2019022) MICRO-ENCAPSULATED TECHNOLOGY: NEW CHEMICAL TREATMENT FOR DOWNHOLE
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The common surface chemical applications cannot reach or have low efficiency due to high fluid levels. This paper Introduces a new chemical technology for all types of artificial lift systems that guarantees an efficient downhole treatment at the entry point and summarizes the applications of this revolutionary method established to deliver chemical combinations by microencapsulating the compounds and packaging the completed formulation in a chemical screen that is placed at the bottom of the tubing (BHA) below any type of artificial lift systems. The new downhole Chemical treatment technology were designed and successfully applied in 3 wells in the Permian Basin to control scale and corrosion. The installation of the chemical tool is easily made up below the pump intake and not additional equipment is needed in the pump or in the surface facilities.

Presented by:

Gustavo Gonzalez, Renzo Arias, Luis Guanacas 
Odessa Separator Inc.

Artificial Lift
Room 110
(2019011) OPTIMIZING SHUTIN TIME FOR PUMP-OFF CONTROLLERS
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Much work has been done on the operation of beam pump pump-off controllers, but the downtime is normally a simple timer and the optimum downtime is usually set by rule of thumb or trial and error. This paper uses a complete well model coupled with a transient reservoir  model to show that the optimum downtime in terms of total energy used per produced barrel of oil is equal to the wellbore storage time from well test analysis.

Presented by:

Walter Fair, InterAmerican Petroleum Consultants

Artificial Lift
Room 111
(2019042 MANIPULATING CASING PRESSURE TO BETTER HANDLE GAS IN CERTAIN WELL TYPES
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Rod pumps are not the ideal system of lift when it comes to handling gas. We can only do so much with the configuration downhole especially for wells with open hole completions. Despite the limited options, we are coming to find that we can do better by manipulating parameters at the surface. Historically, we have manipulated back pressure on the tubing in order to control when gas breaks out of solution in the tubing. Now we are finding, on certain well types, that manipulating back pressure on the casing in order to keep gas in solution through the pump is proving to be successful. By doing this, we are seeing beam wells that now face less equipment stress due to gas interference, more consistent, stable run time and production on a daily basis, and even optimized inflow where production increases for wells. 

Presented by:

Blake Whittington, OXY USA Inc.

Artificial Lift

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

Room 101
(2019025) TAILPIPE SYSTEMS REQUIRE SMALL INTERNAL DIAMETERS
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Horizontal wells can be difficult to produce with artificial lift systems. To address the problems of lifting these wells, tailpipe downhole separation systems have become more commonplace and have proven themselves to be effective at mitigating slug flow and improving artificial lift performance. Production increases of 30% to over 100% are frequently seen and pump run life can improve by 3-5 times in the right applications. However, designing a proper system to improve production and lift performance today and last for all, or a substantial portion of, the remaining producing life can be challenging and counter-intuitive. A key factor in the performance of these type of downhole separation systems is the internal diameter of the tailpipe. A review of 350 tailpipe systems installed in various basins reveals the importance of sizing the optimal internal diameter that balances draw down, slug flow mitigation and longevity as a well declines.

Presented by:

Dave Kimery, Jeff Saponka, Rob Hari and Kyla Gau
HEAL Systems

Artificial Lift
Room 102
(2019047) AN ENCONOMIC AND RISK BASED APPROACH TO OFFSET WELL PREPARATION FOR NEARBY FRACS IN THE DELAWARE BASIN
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With the increase in activity in the Delaware Basin, preparing wells for the pressure spikes seen from offset fracs is crucial in order to maintain safe operations.  It is important to take risk and economics into account when deciding how to prep a well. Most importantly, historical data should be factored into the decision making process and used to build the program guidelines.  Factors that should be accounted for are artificial lift type, surface equipment ratings, producing interval, frac azimuth, and 
relative distance and position to the well being fractured.
 

Presented by:

Ryckur Shuttler and Daniel Benavides
Anadarko Petroleum

General Interest
Room 104
(2019043) APPLICATION OF WATER TREATMENT PROGRAMS TO PREVENT FOULING AND CORROSION DURING DRILL-OUT
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Case study of mill-out operations in the Permian Basin which evaluate chemical program and processes used. Results show how existing processes and chemicals used or lack thereof, can affect equipment and undo the preventative chemical treatments used during the hydraulic fracturing process. The study looks at field water testing performed during various mill-out operations and considered workover rig vs coiled tubing, equipment set up, water & chemicals used, and operational challenges. Water analyses were completed on injection water and returns at various interval of the mill-out. Effectiveness of chemical treatment was also monitored when biocide was used. Four field case studies are presented for horizontal wells. Two wells were milled-out utilizing workover rigs and two wells were completed using coiled tubing. Testing results show the impact of equipment setup and operations process on the water quality and efficiency of the chemicals used. Water fouling was prevalent in all cases, with coiled tubing jobs showing the highest degree of water contamination and chemical inefficiency. Changes in water treatment program during operations showed significant improvement and sustainable results. Potential corrosion of the work string due to water fouling and composition was also observed, and the effects of changes in chemicals were monitored. This is important because it identified operational improvements that can reduce equipment replacement costs, chemical overuse and protect wells from fouling due to high bacteria. This case study provides a comprehensive review of mill-out operations and provides guidelines for improving chemical efficiency and potential of  extending life of the work string.
 

Presented by:

Tanhee Galindo, GeoKimika Oil & Gas

Drilling Operations
Room 106
(2019023) ENERGY SAVINGS ON BEAM PUMP SUCKER ROD SYSTEMS / CONTROL SOLUTIONS WITH FIELD CASE STUDIES
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One of the largest lease operating expenses is electrical cost. Only a small portion of electrical cost is value-added conversion of electricity to fluid lifting power. The rest is lost to downhole friction, fluid flow friction, pumping unit, and electrical to mechanical power conversion inefficiencies.  Overall “line to fluid” system efficiency will typically range from 20% to 40%. Some cases will be as low as 10%.

Some of those energy losses are inevitable.  Some can be reduced through improved operation and controls. This paper will present power studies of various control schemes on actual wells, highlighting the best solutions for reducing power consumption. 

The study will examine: line starters with timers, line starters with pump off controllers, pump off controllers with variable speed drives and advanced embedded controllers. Electrical average voltage(V), power factor, maximum current(A), average current(A), total apparent power(KVA), total reactive power(KVAR) and total real power(KW) will be show for each variation. Apparent costs and ROI of implementing and/or changing to a new control system will be presented.    

Presented by:

Jordan Hanson, Control Solutions

Unico

Hy-Bon/EDI

Artificial Lift
Room 107
(2019016) SUCKER ROD GUIDE IMPROVEMENTS
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Typically, the Petroleum Industry maintains operational ideas that were developed years ago.  These operational ideas may still have merit, but some improvements should be considered.  Sucker rod guides are an example of such practices.  Most production companies continue to use rod guide material that was introduced at the conception of the recognition of the need for sucker rod guides.  This presentation will give information of new materials and new application ideas for sucker rods guides. 

Presented by:

Calvin Stewart,  Stephen Borcik and Steve Gault
OXY USA Inc.

Artificial Lift
Room 109
(2019038 CASING GAS SEPARATOR INITIAL INSTALLATION LEARNINGS AND DESIGN PROGRESSIONS
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A new technology was released last year with the goal of being safe, easy to run and attaining previously unachievable gas separation when compared to any other method available today. The new technology is a gas separator built into the casing (CGS) and is run on the actual casing string right after the well has been drilled. CGS is run permanently into place on the casing with no alteration to the drilling program whatsoever. The CGS is commonly placed at kickoff point or in a tangent further downhole and well work occurs with absolutely no alteration to normal completion processes. The CGS can be run in multiple positions in the wellbore and two were run in the Rockies with different set points. One was at KOP and the other in a tangent. This paper will discuss the prejob planning with the Drilling Department, Completions Group and Production Team. The paper will go into the actual execution of each installation and the outcomes of the installs. The lessons learned led to multiple design progressions and development of ancillary tools to be run in conjunction with the CGS.

Presented by:

Brian Ellithorp and DJ Snyder
BlackJack Production Tools

Artificial Lift
Room 110
(2019037) REDUCING ROD PUMPS STICK IN THE TUBING IN THE HIGHWAY 80 FIELD
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When an insert rod pump gets stuck in tubing there will be a significant increase in well-servicing events. These events cost the consumer money and also places the worker's safety at risk. 


The Highway 80 area reviewed the number of stuck rod pumps in tubing conditions that had occurred from 2010 to mid-2017.  In total, there were 825 pumps that were unable to be pulled with rods, which resulted in tubing being pulled to retrieve the pump. To try and resolve this issue Pioneer used a rubber fin element below the discharge of their insert rod pumps. By doing so they saw a reduction in stuck pumps with the rubber element. Even though this method decreased the number of stuck pumps, about 10% of their pumps continued to get lodged in the tubing. 


In the third quarter of 2017, Harbison-Fischer implemented a design change to these wells. The Harbison-Fischer Brush Sand Shields were installed to all insert pumps going forward.


This paper will discuss the early results of approximately 18 months since the first Brush Sand Shields were installed. We will compare the pumps pulled that were stuck in tubing with and without the design change since the implementation. Our goal is to continue to review the trend to see if positive results are achieved. We will track the data and present it again in 2020. We have calculated that the additional cost of pulling tubing is more than 50% more than if the pump can be retrieved with the rods.
 

Presented by:

Rodney Sands, Apergy - Harbison-Fischer
Rowland Ramos, Pioneer Natural Resources
Matt Horton, TWS Pump

Artificial Lift
Room 111
(2019048) IMPACT OF PRODUCED WATER ON THE CORROSION OF STEEL BY CHLORINE DIOXIDE
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The perceived impact of chlorine dioxide (ClO2) on the corrosion of steel used in the oil patch has been a controversial issue for many years.   Although a few studies on this issue have been published, those results have been contradictory. As concerns surrounding this issue continue to be raised, a systematic study has been undertaken to understand the corrosive effects of ClO2 towards steel in various produced waters.  Research shows that the baseline corrosion rate of untreated produced water is related to TDS, with other factors being involved, such as the presence of H2S and iron. This paper summarizes the results of other studies that have been done, and demonstrates the contradictory nature of such studies. The results of this on-going study show the relationship between the TDS of produced water and corrosion resulting from use of varying concentrations of ClO2.  The paper explains the contradictory nature of corrosion caused by ClO2.

Presented by:

Greg Simpson, Purleline Treatment Systems

General Interest