Pumps are the heart of a rod pump system, but as operators, how much do you know about the pumps that are being run into your wells and how they are being repaired.  This paper will briefly describe pump repair procedures, best practices that the shop should be following, and a pump shop inspection report that helps identify if those procedures are being followed. It will cover what pump failure data should be captured, why it is important, and what type of information may be available in report form. Many operators do not realize that you can gain valuable well and operational data from a pump report besides what is needed to optimize the pump alone. It will also explain how the operator should get involved in the decisions that affect the pump design and repair which can affect costs and run life.  

Fluid Extraction Technology can improve down hole gas separation by employing material and fluid flow properties in ways that are not now effectively utilized.  Downhole pumps that handle fluids are adversely affected by free and entrained gas entering the inlet of the pump.  To separate the gas ahead of the suction of pumps in the bottom of a well, operators typically configure a path for the fluid to be redirected downward to allow the gas to rise while the liquid falls to the intake of the pump.  Virtually all of the gas separators use single pass serial separators based on gravity.  The primary separation is typically the tubing by casing annulus and the second stage of separation is the labyrinth of falling liquid and rising gas inside the mud anchor or packer assembly.  This technology can be very effective but often times is not sufficient.  In addition, the size and length of the equipment has a larger material footprint than necessary.

Fluid Extraction technology uses gravity but also uses mechanical and fluid properties to enhance separation.  These attributes include wettability, fluid adhesion, gas nucleation and the concept of Liquid hold up or circulation cells.  Integrating these concepts allows better use of the primary flow volume of the casing by tubing annulus.

The full potential and benefits of the fiberglass sucker rod (FSR) are not being realized.  FSR manufacturers are toned to meet the requirements for increased operating ranges and one-time pull loads of FSR.  Increasing the operating load requires the redesign of the end fitting to ensure reliability.  This paper outlines the standard design of an end fitting and how it interfaces with the pulltruded fiberglass rod. The test data used to validate the design is also included.  The overall wedge design is explained in detail, demonstrating the interaction of forces acting on the rod/end fitting interface. The stress range diagram will be presented with emphasis on the critical areas of the end fitting design. The overall goal is to show how fiberglass is stronger than steel.

A companion paper is being made to show the graphical analyses for the wells that Sandia measured surface and downhole loads at various depths with a special downhole load cell.

This paper will provide an analysis of the operating conditions that were occurring that resulted in these downhole dynagraphs. Additionally, these operating conditions will then be entered in three available industry rod string design programs that include: QRod, SRod and RodStar to see how accurately these design programs predicted the actual, measured loads.

Improved rod tongs have recently been introduced for rod connection make-up and break-out in the field, with the purpose of reducing sucker rod failure rates. This paper will compare one of these tongs to the present industry standard sucker rod tong, comparing and contrasting each tong’s capabilities, advantages, drawbacks, and effect on rod string performance in the wellbore. In addition, basic job time studies, best practices, and suggested well selection criteria will be discussed.

Sucker rod pumping applications are the oldest and most widely used means of artificial lift for oil wells. The pumping performance and the longevity of the pumping systems with their corresponding pump parts have improved significantly throughout the years, but the failures remain inevitable. These failures are costly and time consuming for operators, but analyzing those enables us to improve the part design and the decision process of part selection for certain well conditions, and minimize future failures.

This paper focuses on pump barrel selection and operation with regards to base metallurgies coupled with various plating processes. It aims to inform the reader of common pump barrel failures and their causes, along with educating operators about available barrel types and their optimum operating environments.

The benefits of the Beam Gas Compressor® for rod pumped wells has now been modified to a standalone version. Allowing the technology to facilitate a broader range of operations and objectives.  Historically, the Beam Gas Compressor® has been installed on pumping units and utilizes the prime mover of the pumping unit to drive a piston inside a proprietary designed cylinder. This paper describes how this technology has been adapted to a standalone compressor installation, how the changes allow more versatile uses and how the technology compares with other types of compression.

Typical production profiles using a decline curve are then used with IPR equations to predict IPR expressions with time into the future.  Then using application rules such as limiting depths and rates, gas separator feasibility for pumps and flowing well and gaslift calculations from Nodal programs, Artificial Lift possibilities are mapped out into the future.  The techniques are not limited to the production profiles used as an example. 

Wireless high-frequency motor power-current-voltage measurements are used to analyze the electrical and mechanical performance of pumping units.  The sensors can be mounted permanently in the electrical box with a water-tight connection on the side of the electrical box for attachment of a small plug-in radio for wireless communication to a PC base station.  These measurements can be performed without opening the electrical box.  In addition, starter boxes without internal sensors can be analyzed using portable sensors that require opening the box and attachment of two current and three voltage sensors.

TAM Software in the PC receives and analyzes the data to determine power usage, power generation, pumping unit balance, gear box upstroke and downstroke torques, motor loadings, and power line loss.   Power line loss is an analysis performed to analyze the power line loss between the electrical system and the pumping unit motor.  The counter-weight movement for gear box balance is determined easily without use or knowledge of the pumping unit dimensions. 

Many operators in the Permian Basin have moved from drilling vertically to developing leases with horizontal drilling.  After implementing a horizontal drilling program, three critical challenges emerge:  1) selecting the most efficient means of initial production; 2) using a rod pump design without experiencing gas interference or losses in volumes; and 3) handling a horizontal well at pumped-off conditions.  Drawing the well down as quickly as possible is ideal for generating the best economics. The initial investment and operating costs of the artificial lift system must also be considered when performing economic analysis.  Rod pumping horizontal wells to produce the high rates that the model describes is challenged by gas interference which has resulted in the following: rod and tubing wear, upper buckling tendencies, increased man hours trying to resolve problems, and a loss in production.  When pumped off conditions occur while rod pumping from the kick off point, a noticeable decline in production can be observed.  In low pressure reservoirs, lowering the pump into the curve can prove to restore or even increase production rates.  By studying past cases of producing Yeso horizontal wells in the New Mexico Shelf Platform, COG has been able to select an optimally sized ESP, smoothly convert to a rod pumping system to achieve pumped off conditions, and continue to produce in the curve to avoid losses in production.

When using artificial lift, namely sucker rod pumps, there are three major factors to consider when trying to control and optimize production: elasticity, viscous friction and mechanical friction. The Modified Everitt-Jennings uses an iteration on dual damping factors to approximate the correct amount of viscous friction to be removed to mimic the energy lost through the viscous forces imparted on the outer diameter of the rods by the fluids. A precise Fluid Load Line Calculation provides a concavity test to diagnose the presence of mechanical friction.

Secondly, in order to maximize production and prevent rod string damage, pump-off control technology must be used in conjunction with sucker rod pump installation. The most accurate type of pump-off control is one using pump fillage. The Modified Everitt-Jennings combines an in-depth stress analysis with a powerful Pump Fillage Calculation, which outputs correct pump fillage regardless of downhole conditions present.

In this paper, a complete methodology for controlling sucker rod pumps is presented. This methodology combines state of the art, innovative methods that smartly and efficiently automate the control of sucker rod pumped wells.

In the case of a vertical well, the rod string can be compared to an ideal slender bar. Therefore the propagation of stress waves occurring from cyclic loading and un-loading during a pumping cycle becomes a one dimensional phenomenon.

The most accurate way of computing downhole data, is therefore by solving the one-dimensional damped wave equation. The Modified Everitt-Jennings algorithm combines finite differences with other state of the art innovative algorithms to provide precise downhole data, accurately reflecting present downhole conditions.

In the 1990’s, Sandia National Laboratories were contracted to measure actual position and load data at different depths of the rod string through a series of downhole tools.

In this paper, results from the Modified Everitt-Jennings methodology are compared to actual field measurements, captured by the Sandia National Laboratory experiment.

The Electronic Downhole Load Cells (DHLC) was used during the mid-1990s to acquire downhole dynamometer data.  The unique DHLC was mounted at a desired location in the rod string (usually between two rod tapers).  Dynamometer data was collected while the well operated.  SANDIA coordinated collecting DHLC data on six (6) different types of wells.  The petroleum industry provided wells and SANDIA collected, de-coded and presented the data.  NABLA and others concurrently acquired the surface Dynamometer measurements.  DownDYN software developed by SANDIA was used to display and export the collected data.

The dynamometer data acquired at each rod taper for each well will be displayed.  The DownDYN software is no longer supported by current Windows Operating system.  This valuable information will be lost, if the DownDYN software is not modernized.  Downhole Load Cell data measured at the pump resolved the display of the downhole pump loads. This paperwill discuss the true/effective load argument for display of downhole dynamometer data.  

A new term “Equivalent Gas Free Pump Fillage Line” represents the amount of liquid fillage inside the pump chamber when the traveling valve opens during the down stroke.  Adjustments for gas in solution, slippage, free gas, and compressibility of liquid due to pressure and temperature are required to determine the amount of stock tank liquid produced per day for a selected stroke.

Field dynamometer data from eight different wells will be used to compare the calculated to measured surface oil and water production volumes.   Equivalent gas free pump fillage line will be shown for each well’s representative pump card.

The pump card calculated gas produced up the tubing and the acoustic fluid level tested free gas produced up the tubing/casing annulus are used to determine system gas separation efficiency.  This enhanced analysis technique allows answering many complicated questions concerning oil, water, and gas production with respect to the downhole pump card.

We explore how minor modifications in routine usage of typical rod pumping equipment may improve the performance of rod pumped wells; e.g. how initial proper selection and implementation of polished rods and can limit well failures.  Also discussed are pump design changes to mitigate common pumping problems, and why standardized pump designs are not over-all beneficial to producing wells.  Additionally, we illustrate that standardized or “common” downhole design limits production rates

This paper will highlight the use of high liquid volume plunger lift to date in the Southern Delaware Basin.  This method of lift was first considered by COG Operating, LLC in an effort to bridge the gap for taking a well from flowing to rod pump.  Historically in the Southern Delaware Basin this was accomplished with high cost electric submersible pumps.  One of the criteria for success was that plunger lift would be able to replace the electric submersible pumps and economically maintain the well on its natural decline.   To date, COG has eight wells that have been successfully operating with high volume plunger lift. Representative decline curves will be presented, along with operating pressures and histories on the successful wells in the project.  The paper will be presented both from the prospective of the operator and then operating criteria from the vendor that have made this project a success.

Knowledge of the magnitude of different components of mechanical torque acting on the gearbox is crucial for the design and analysis of sucker-rod pumping installations. Gearbox torques include the torque required to drive the polished rod and the torque used to rotate the counterweights. In addition to these, inertial torques arise in those parts of the pumping unit that turn at varying speeds. As shown in the paper, all torque components are functions of the crank angle, consequently their exact calculation necessitates the knowledge of the crank angle vs. time function. This circumstance, however, complicates torque calculations because contemporary dynamometers, used to acquire the necessary operating data, do not provide any information on the variation of the crank angle during the pumping cycle. The paper introduces a solution of the problem and presents an iterative calculation of the crank angle vs. time function from dynamometer data. Based on this function crank velocity, acceleration, as well as beam acceleration are easily found and all necessary gearbox torques can be evaluated. The paper describes the details of the developed calculation model and presents example calculations.

The early detection of "sweet spots" for oil/gas well site selection and fracturing in shale reservoirs is a challenge for many operators. Most of the time, unique parameters are utilized (i.e. brittleness based on geomechanical and geochemical parameters) to determine the "sweet spots" for well site placement. Additionally, the fractures are generally placed equidistantly. 

This may create short transverse and/or non-planar hydraulic fractures that are problematic during hydraulic fracturing and may create suboptimal production.

This technology utilizes an integrated approach to site selection and fracture sequencing that allows for the optimal productivity of the well. 

This integrated approach utilizes both petrophysics and geomechanical data to develop a Fracturability Index to guide well site selection and fracture positioning in unconventional shale plays. It also, introduces an optimization approach based on mathematical formulations to guide scheduling of fracturing operations in big resources.

In the hydraulic fracturing industry, it has been a long-time problem and struggle to accurately track the usage of chemicals on fracturing site and make proper management decisions.  The manual approach has measurement error and the chemical inventory information cannot be accessed by people such as directors or managers who may not be on site but need the critical information for decision-making. Obtaining chemical inventory information automatically and making it available on-line would significantly save material costs, enhancing asset management efficiency. In a designed system, a guided-wave radar level sensor is used to measure the chemical level and the chemical inventory data are updated on an internet server through the satellite internet in the control van, making the information available on-line for engineers, managers and clients. The proposed monitoring and inventory system will greatly enhance asset management efficiency and reduce cost for the oil and gas industry. 

Worker safety is a vital part of the oil and gas industry. Enviroklean Product Development Inc. (EPDI) increases worker safety through education and training on Naturally Occurring Radioactive Material (NORM). EPDI offers several different training levels including NORM awareness, NORM worker, NORM surveyor and NORM Radiation Safety Officer (RSO). Education combined with enhanced surveys and analysis of NORM by gamma spectroscopy allows for accurate readings of NORM on a job site. The gamma spectrometer is an instrument that measures the energy and intensity of radiation in a sample such as soil, scale or sludge.  EPDI in conjunction with the Nuclear Engineering Teaching Lab at the University of Texas has developed a gamma spectrometer and computer program that allows for real time on-site results within 15 - 30 minutes.  We have also used MCNP (Monte Carlo N-Particle) to establish a comprehensive and flexible computer model to realistically estimate the radiation dose absorbed by a field worker.

Amerada Petroleum drilled the first producing oil well in North Dakota in 1951. When Amerada and Hess merged, it provided Hess with a strategic position in North Dakota for the shale oil boom, assisting Hess in the acquisition of almost 900,000 acres at peak.

The initial development plan for North Dakota was 3 Bakken wells per Drill Spacing Unit (DSU) covering 1280 acres of total spacing. The discovery of the Three Forks formation and the success of infill drilling and tighter spacing increased the total anticipated well count for Hess in North Dakota to over 4,000 wells.

The expected well count in North Dakota increases the long term OPEX (failures) concern. With the current failure rate approaching 0.5 failures/well/year, 2,000 failures per year would put a massive burden on resources. This paper will review the process Hess has adopted in order to manage and decrease failure rate while increasing the total well count.

Improving Paraffin Treating by Modernizing Chemical Applications: A Case Study of Pressurized Injection vs Positive Displacement Pump

This paper describes a novel technology that applies paraffin inhibitor with a pressurized injection system. The technology uses nitrogen gas to pressurize a chemical reservoir.  An electric programmable valve controls the flow of chemical out of the reservoir.  Adding an electric programmable valve to the flow line integrates chemical treatment and flush operation.

Pumping units using the pressurized chemical system have been able to increase the time between well interventions due to paraffin deposition.  

Performance of the treatment and integrated flush improve chemical delivery and improve chemical performance.

Satellite telemetry allows users to remotely monitor the chemical usage, inventory, and reservoir re-filling to add a level of confidence and dependability to the system.  The system can tie to either the pumping unit or well PLC/POC to only operate when the well is operating.

Determining the optimal equipment layout for an oil and gas facility must consider hazards resulting from a fire, explosion or toxic gas releases.  Over the years, many incidents have occurred where workers were injured or equipment was damaged by explosions, fire or toxic gas releases when equipment or occupied structures were not located properly. This paper presents “state of the art” techniques to allow facility designers to optimally locate equipment to reduce the risk of injury and equipment damage.

This paper reviews current industry “best practices” and also presents examples for the proper layout and spacing of equipment at oil and gas facilities.  The techniques presented in the paper enable the facilities designer or Engineer to quickly gather the information needed for the analysis, evaluate credible scenarios and then make the necessary judgments to properly locate equipment.  The result of using the information presented in this paper is that equipment and occupied structures are properly located and spaced to reduce operational and safety risk.    

: Paraffin is one of the major flow assurance problem in west and south Texas.  The mitigation techniques for the case of onshore paraffin deposition is different from the offshore case.  Chemical treatment is used instead of a pigging method for the onshore case.  The current reliable methods for the onshore paraffin treatment are (1) downhole chemical injection, (2) solid paraffin inhibitor pumped during hydraulic fracturing, (3) hot water or oil circulation.  The magnetic conditioning is also being 

used in some field, despite the lack in the understanding of this method.  

This paper reviews the current understanding in paraffin deposition problem (single-phase, oil-water, gas-oil), mitigation technique and its current development.

Accurate prediction of the behavior of multi-phase flow through wellhead chokes is required for modern production design and optimization of oil well performance.

This study presents the development of an empirical correlation that predicts the performance of simultaneous flow of oil, gas and water mixture through wellhead chokes. The correlation was derived on the basis of actual production data. The newly developed correlation predicts liquid flow rates as a function of flowing wellhead pressure, gas/liquid ratio and surface wellhead choke size.

The study involves a comparison between the available choke correlations based on 200 field tests from twenty wells. The correlations used in this study are those of Gilbert, Al-Attar, Ros, Baxendall, Achonge, and Secen. The Absolute average percent difference is computed for each correlation. Secen correlation has the lowest error compared to the other examined correlations. However, none of the tested correlations is found to be accurate in all ranges of wellhead pressure, gas/ liquid ratio and choke size. The validity of each of these correlations is limited to a specific operational condition for which the correlations are determined. As a result the strength of those correlations for predicting the actual flow rate is restricted.

Due to discrepancy of results obtained by the included correlations, multiple regression analysis using the statistical technique using the Doolittle method is used to create correlation that best fit the measured data. The proposed correlation is similar to the Gilbert-type empirical correlation.

The new correlation was examined against other correlations using another 110 well test data. The results are found to be statistically very good compared to those predicted by other published correlations considered in this work.